Good day, everyone, and welcome to the Apache Corp. First Quarter 2011 Earnings Conference Call. This call is being recorded. Today's presentation will be hosted by Mr. Alfonso Leon, Vice President, Planning Strategy and Investor Relations. Mr. Leon, please go ahead.

Good afternoon, everyone, and thanks for joining us for Apache Corporation's First Quarter 2011 Earnings Conference Call. This morning, we reported first quarter 2011 net income of $1.1 billion, or $2.86 per diluted share. Adjusted earnings, which exclude certain items that impact the comparability of results, also totaled $1.1 billion, or $2.90 per diluted share. Cash flow from operations totaled $2.2 billion. On today's call, we'll have 4 speakers making prepared remarks prior to taking questions: Steve Farris, our Chairman and Chief Executive Officer; Rod Eichler, President and Chief Operating Officer; Roger Plank, President and Chief Corporate Officer; and Tom Chambers, Executive Vice President and Chief Financial Officer. We've prepared our usual detail supplemental data package for your use, which also includes the reconciliation of any non-GAAP numbers that we discuss, such as adjusted earnings, cash flow from operations or costs incurred. This data package can be found on our website at www.apachecorp.com/financialdata. Today's discussion may contain forward-looking estimates and assumptions, and no assurances can be given that those expectations will be realized. A full disclaimer is located with the supplemental data package on our website. With that, I'll turn the call over to Steve.

Thank you, Alfonso, and good afternoon, everyone. As I'm sure all of you are aware, Apache this morning announced its financial results for the first quarter of 2011. During the quarter, we achieved record production of 732,000 barrels of oil equivalent a day. We also posted our third highest quarter of earnings ever, as Alfonso pointed out, $1.1 billion, and our second highest cash flow ever of $2.2 billion. The reality is that we faced a number of unexpected external challenges around the world since the beginning of the year: In Australia, we have suffered 6 consecutive cyclones and have had problems with third-party FPSO; there have been some social unrest in Egypt; and like many people, the Permian and central regions closed up during part of February; and then on top of all that, the U.K. government decided to raise taxes in the North Sea. You would think our performance would have suffered, and it did somewhat. But despite the challenges, Apache produced near-record financial results and had broad-based drillbit success with multiple new field discoveries. And Rod Eichler will walk you through some of these in a moment. I'd like to take stock of what drove Apache's performance in the quarter, and it really comes down to a few things: It's really our portfolio strength, our people and our culture. The one thing we've learned as a company over 5 decades, that if you want to make money in the oil and gas business over the long haul and not just now, you need to have a broad-based and well-balanced portfolio of quality assets, and you need to build a culture based on asset focus and returns. And on the portfolio side, producing 358,000 barrels of liquids a day, 92% of which is crude oil, certainly benefited our…

Thank you, Steve. In the central region, production in the first quarter was down sequentially due to disruptions from unusually cold weather. Apache operated 12 rigs in the region during the quarter and drilled 23 wells, of which 20 were horizontals, with an 87% success rate. There are 3 highlights I'd like to note in the central region for the quarter. Firstly, we've drilled the first dual lateral well by any company in the Granite Wash. This well targeted 2 different horizontal members of the Granite Wash from a single vertical wellbore. The lower zone was completed at an initial rate of 6 million cubic feet of gas per day and 220 barrels of oil per day. Two months later, the upper zone was completed at an initial rate of 6 million a day and 40 barrels of oil per day. Using this method realized $2 million in cost savings in this first application alone, compared to drilling 2 single horizontal wells. Secondly, we completed the first horizontal test of the Granite Wash C formation [Marmaton C formation], achieving a test rate of 6.8 million cubic feet of gas per day and 180 barrels of condensate per day. And thirdly, in the Cherokee oil play, we completed 2 wells, one for 950 barrels of oil per day at 1.5 million cubic feet of gas per day, and the other for 425 barrels of oil per day and 725 Mcf per day. We intend to drill 20 more Cherokee oil wells this year. And oil drilling, including the Hogshooter zone, represents nearly half of our central region activity. We'll have a greater detail on these plays during our Analyst Day in May. Moving to the Permian. Production was down sequentially due to the impact of extreme cold weather-related freeze-ups compounded by…

Thanks, Rod. And as you've already seen from our press release and heard earlier on this call, we reported earnings of $1.1 billion, or $2.86 per share, for the first quarter. Adjusted for certain items that impact the comparability of results, such as foreign currency fluctuation on deferred taxes and merger acquisition and transition cost, we earned $2.90 a share, up over 30% from the current -- prior quarter. Higher daily production, combined with significantly higher oil prices, increased cash from operations 13% over the fourth quarter to $2.2 billion, our second highest quarter ever, and just the third time we've broken $2 billion per quarter. As Steve indicated in his opening remarks, our broad-based, balanced portfolio continues to deliver excellent results. Our oil and liquids volumes currently make up 49% of our total production, but account for 77% of our total revenue. More than half our total revenue is generated outside of North America, driven by our portfolio of crude production indexed to Brent Oil price, which is currently running at a $10 premium to WTI, not to mention increasing gas prices in Australia and Argentina. With higher oil prices and oil exposure comes pressure on costs, including drilling and services. However, we were able to hold the line on our costs in the first quarter while expanding our cash and pretax margins by 23% and 37%, respectively, excluding merger, acquisition and transition costs. Cash margins rose over $8.00 per boe to $44.10. And pretax margin, which includes DD&A, rose just under $8.00 of boe to $29.33, which is about 50% margin. You could find the details of these both on the financial supplement located on our website. One cost I would comment further on is gathering and transportation. You would note a significant increase over the fourth quarter…

Okay, thanks, Tom, and good afternoon, everyone. Tom talked about the quarter relative to the prior quarter. And I wanted to go back to first quarter a year ago to underscore how significantly our situation has changed, and how that impacts our view and direction going forward. In a world scrambling for oil, Apache's oil and NGL production was up 57,000 barrels per day, or nearly 20%, with first quarter realization some $20 higher from a year ago. Furthermore, second quarter oil prices have risen another $10 to $15 to date over first quarter levels. Accordingly, we are benefiting from extremely strong earnings and cash flow that enhance our financial flexibility relative to both our competition and to our initial 2011 plan in several ways. First, the growth of our international regions means Apache is a leading beneficiary of today's $10 to $15 per barrel premium of Brent over WTI. Over half our oil production is Brent. Second, as a result, we are building cash balances rapidly, particularly abroad. Apache has now joined the ranks of those profitable U.S. multinationals with growing cash balances outside the U.S. that cannot be brought back tax-efficiently. That limits us from using our rising cash balances to reduce debt, which is predominantly in the U.S., which is why our debt outstanding is flat quarter-on-quarter despite $0.333 billion of cash. Consequently, we've adjusted our views in the following manner. We have tempered our plans to sell international assets in Canada, and we'll retain some properties earlier earmarked for sale. We now expect Canadian property sales to total something less than $0.5 billion. On the other hand in the United States, where we have the twin objectives of both reducing debt and increasing capital, we are reviewing the possibility of selling some small non-core assets. Looking…

[Operator Instructions] Your first question comes from the line of Brian Singer of Goldman Sachs.

On the back of some of the successes that you discussed in Egypt, how interested are you in accelerating investment there to develop some of those successes? And do you see any constraints beyond -- or the political constraints, do you see any constraints on the gas processing side?

Well, a whole lot. Rod will really get into the details. This is Steve. But in terms of the -- we're going about it as fast as we can go. I think we're going to spend about $1.1 billion in Egypt this year. And the gas processing is really limited until we get that gas pipeline going south. And I think we made that point when we made the acquisition of BP's assets in Egypt. And I'll let Rod bring you up to date as to where that process is.

Right. Brian, as I mentioned in my remarks, we have increased the gas production in that Abu Gharadig plant that we got from BP, and we're doing some work inside that plant to restore some of the facilities that we've had some -- problems we've had this past quarter. But nonetheless, we anticipate the intelligent pigging, the final pigging evaluation of that 24-inch, 262-kilometer line from Abu Gharadig to Dashour LPG plant, that should take place sometime in the latter part of May. Once we see that, we'll know to what we can re-rate the pipeline to perhaps its original throughput. We have every expectation to be able to bring gas from our Khalda areas along with the gas produced from the Abu Gharadig field area I mentioned, to ramp that up to perhaps the 7,840 million a day if the pipe's in good condition. And so far, everything looks good, from we've seen in initial pigging stages.

And so when we think about, say, the new Paleozoic discovery and the potential for that to open up a new play, is that something that we should think about as having more of a longer-term impact out a few years by just further continuing the same growth trajectory you're on for a longer number of years? Or is that something that could have more of a medium-term or near-term impact?

Well, I think that right now, it appears to be -- it was a structure that we drilled, a similar line of structures based on our 3D like we see in the adjacent parts of the western basin in the Faghur basin area. What's unique about it is it's a Paleozoic reservoir that was charged with oil. And we see many other structures continuing west. It's the frontier part of Egypt there. There are really few wells drilled in this part of Egypt. We're very close to the Libyan border, and this is exciting. This is probably the -- this will the furthest, most westerly production in the country.

Got it, thanks. And then in the U.S., you mentioned you're considering accelerating activity there, can you just talk about the ease that you expect to get additional rigs and frac crews? And do you see any synergies already? Or any gains from scale in places like the Permian, where you now have a bigger position?

Well, we have about 25-rig program operating in the Permian, and the guys are running full out. Of course, there's supplies, services, everything is pretty tight in this kind of high-oil-price environment, but we have everything we need to see us through the year for our program that we have budgeted.

I guess my question was more along the lines of accelerating from here. I think your indication that you're considering accelerating onshore North America, maybe you could add a little color on where you think that might be, if maybe it's not the Permian, it's the rank out of its tent [ph]?

Well, the prospect inventory opportunities are certainly in the Permian. We a see large inventory of locations. We just only scratching the surface in many of these plays. Well, as you know, the beginning stages of horizontal exploitation in many of these reservoirs that traditionally have been tapped by vertical wells over the last 100 years. We're seeing a lot of very promising results there. I also see continued acceleration and growth in exploitation in our Granite Wash program in Oklahoma and the Panhandle of Texas. We have a substantial inventory of locations to be drilled. So it's just a matter of how much we want to apply to the program to move forward.

Your next question comes from the line of Doug Leggate of Bank of America Merrill Lynch.

I'll try 2, one, I think, general, and one also on Egypt, if I may. Just in terms of your capital expenditure and your cash flow, I mean it's pretty obvious what's going on in terms of the relative strength of cash flow. But I'm just curious, what are the operational constraints surrounding your ability to actually spend capital, particularly in the lower 48. I guess what I'm getting at is that it's all very well seeing all the cash flow, but to what extent can you efficiently reinvest that capital?

Well, you're really constrained by [indiscernible]. Physically, the only place we're really constrained in terms of not having services is in the Gulf of Mexico. And the fact of the matter is you can get services for a cost. And the question is what kind of cost you want to pay and what kind of rate of return do you want. Or what kind of rate of return do you want. And also, how do you look at your overall balance sheet. Because it really is a balloon, it's a balance. So we're going to -- it's not rocket science just to figure out we're going to have some more cash and we're going to spend it while we stick to our commitment of paying down some of our debt. But having said that, it's an opportunity-driven thing in terms of rates of return more than anything. I mean, we've got lots of places to spend money, and we're going to spend them in the highest rate of return projects we've got. And right now that's going to be in the Permian Basin for oil and the Granite Wash in the Texas Panhandle.

I guess, Steve, what I was kind of trying to get to was in terms of your own internal people, your capability to actually absorb significantly. I mean, what's the limit on the...

You mean organizationally?

Yes, right, in terms of your capability to actually absorb more activity levels.

Well, I would tell you probably the biggest -- the Granite Wash, we could absorb, just because that region, if you remember, we split those 2 apart. And we had to rebuild, and we were very damn fortunate because we started rebuilding it before we ever got big in the Permian Basin. We were much smaller when we started that activity. But in terms of limitations of big jumps, and I'm not talking about another 10 rigs, but big jumps in activity in the Permian, it's going to take us a little while. Because we're just going to get the manpower out there. But if you look at where we've come and where we are today in the Permian Basin, I mean we're -- we were running 5 rigs this time last year, we're running 25 right now. We'll be running 25 all year, probably, or more. So that's a big jump.

So that's not a factor? In the organizational issues, it's not a factor on maybe why the BP assets haven't seen a lot of activity lately or to date?

You know what, I've got a -- you've got to understand, and I can't say this enough. We're going to take the best prospects we have. And so if they're BP prospects, we know we made a good deal there. I mean it becomes more and more obvious every day, just in the things that we're working on right now. But it also -- we don't have to drill all the wells that we've got on the Permian Basin, BP, in this year. We got a lot of places to spend cap on. It's really the balance of the portfolio, not do we have prospects to look at in BP. I mean, we could put another 25 rigs running today on BP assets, but we're just not going to do that. And hopefully you'll see more on that on May 17. You'll see a broader array of opportunities. It's just a question of which ones we're going to focus on at the current time.

Okay. I appreciate your answering that, Steve. the more -- I guess, the more detailed question is on Egypt, because clearly, your volumes were up despite a significantly higher oil price. I guess, Rod, what I'm curious on is you've always talked about repeatability of your drilling program out there. Can you just talk about how the 100,000 barrel a day target in light of the success you had, in light of the additional capital, in light of the BP assets, why is that number -- why are we not seeing that number skewed to the high side in terms of over the -- your targets may go there as your activity level moves forward?

We're just at the beginning stages. We're 9 months into the 100,000-barrel deal over 5 years, and the objective is to meet that. And with the BP acquisition of the 602,000 acres, those 3 development leases, we may indeed exceed the 100,000 barrels, and maybe even before the 5 years is up. It's really too early to see large additions. We just began drilling on the BP properties just since November, when we took over operatorship. So it's a little slower. Let's face it, since January 25, things are not the same in Egypt with regard to the government processing of paperwork. It's been almost at a standstill in February and early parts of March. So we've had some slowdowns, though operationally in the field, there's been no material slowdowns. But getting approval for routine things like development leases, it's been slow. But I expect that, that will change as we go forward.

And it is [indiscernible].

Yes. It is, yes.

Your next question comes from the line of David Tameron of Wells Fargo.

Can you just give us a little more color on the Cook Inlet, what you're doing up there, what you're chasing? Just a little more color than what you talked about.

Well, it's principally an exploration play in what had been considered to be a mature province. The one thing we've done is there's a lack of any regional coverage of any kind of a modern 3D seismic program, which really, in our experience, makes a big difference in your opportunities to drill successfully. It's a very robust petroleum system, a lot of oil in place. A lot of areas have not been covered by seismic, nor the existing seismic is suitable for modern-day prospecting purposes. And we have, of course, with the early stages of all this activity, but that was kind of the concept we went to this area.

All right. Moving over to the Granite Wash. You talked about $2 million cost savings on that dual lateral. Can you tell us what your cost was, and if you're planning on doing more of this going forward?

That's about a -- on that first example, that's about a 12% to 15% cost savings of a dual lateral versus 2 single lateral horizontal wells. In that area, those costs run about $9.5 million for a single lateral. That's for, like, a 4,000-foot lateral.

Okay, all right. And then going forward, is this a one-off, or is this something you plan putting on the development program? Or how -- can you talk about, going forward, what your plans are?

This was, clearly, is the first time it's ever been done by anybody. This was clearly a test of concept. As you know, there are many stacked washes in this part of the Anadarko Basin, and we have every intention of expanding the technique and trying it in other areas, different zones. So it's just the beginning for us, first well.

And it's not much different. We've got pad drilling in our Horn River with the frac manifold we've come up with to be able to do that in a -- really, for a smaller area and do more things. And I will tell you, the same thing's going to happen with -- in the United States, with dual laterals. And one of these days, you'll probably have quad laterals just because of the cost versus the space that you have to take up. I mean, it's much more efficient. It's just you've got to learn how to do it. And this was our first one, and it turned out to be pretty successful.

All right. And then one more. Australia, you kind of alluded to it with Van Gogh. Can you talk about the FPSO and some -- kind of how you see that playing out in the next couple of quarters?

As you know, In the fourth quarter of 2010, we had some difficulty with the turret mooring seals, and subsequently, with the mooring anchoring system, that came as result of a routine inspection. We've made temporary corrections at both of those. And in fact, the field presently is -- the gross production there runs about 27,000 to 30,000 barrels of oil per day. But it's still less than our 40,000 to 42,000 barrels a day that, that field was producing when we went offline for those initial repairs back in the October-November time frame. Going forward, our plan is to work with the operator of the vessel to fully restore the production that we had achieved previously by making some additional repairs to the previously referenced turret mooring seals. And that may indeed involve some dry dock time for this vessel to effect the appropriate level of repairs sometime in 2012. And our initial estimates is it could be -- that could be as much as much as 4 months of downtime, based on our current engineering evaluation.

Okay. And then it sounds like you said 2012 issue with 4 months of downtime, is that right? Is that what I heard?

That's correct. Possibly, yes.

All right. And so is the implication it runs at that -- if it's going to run a lower rate the rest of this year until you make the assessment?

We just have a few points on the curve that we'd like to -- our target is to get up to the 40,000 range, gross. I think if we can achieve a consistent rate at 30,000 with less mechanical problems, we'll certainly be happy with that as the interim product. But we'd like to factor fully.

Your next question comes from the line of Mark Polak of Scotia Capital.

A question for you on the acquisition of the interest in the Nelson Field. You guys have stayed pretty busy around Forties there with the Maule and Bacchus discoveries, and now this. Do you see further opportunities to consolidate that Nelson Field? And are there any synergies given the proximity to Forties for you?

Yes. We've had our eye on the Nelson Field for many years now. It's literally adjacent, a mirror image to the Forties complex just to the southeast. Very close, I mean, you could see their platforms from our platforms. It's a natural fit to our program. Same depositional channel system that goes from Forties. A little bit lesser quality in the reservoir rock compared to what we have in the Forties, but nonetheless, it's an attractive field. Really, we'll have a 10% non-operating interest, but this gets us in the door. And I think we will have a lot to contribute and suggest to improve the general operations and how to approach cost savings and so forth going forward, and perhaps give us the opportunity to gain additional interest in the field, to preferential rights in the future.

Your next question comes from the line of Leo Mariani of RBC.

Just sticking with the North Sea for a second there. What did that interest in that Nelson Field cost you guys?

Well, we haven't -- everything's not -- the deal has not closed quite this yet at time -- I'd say at this time.

Okay. So I take as that I expect you to close in the next couple of months? Just wondering if there's any type of time horizon on that?

Yes. We're waiting on a final governmental approval, which we expect to receive imminently. I think the closing will take place sometime in the next 10 days.

Okay, I understand. I guess in the Granite Wash, you guys mentioned picking up this pretty sizable ranch here, Bivins Ranch. That it was around 122,000 acres. I thought that was your comment there. Do you guys operate that? And what's your working interest on that? I'm trying to get a sense on how much you paid for that.

We will operate the entire 122,000 acres, the seismic, as well as the drilling. We have a 75% working interest in the operations.

Okay. And what did you guys pay for that?

We're not disclosing our price per acre on our land transactions. We have competitors in the area.

Okay. And do you guys expect to potentially pick up more acreage in the Granite Wash as well, I guess?

Yes, we're continuing to try to add to our position at Granite Wash, both in Oklahoma and the Texas Panhandle.

Okay. Switching topics over to kind of the LNG side. Any progress that you guys have made on contracts there, whether or not it's Kitimat or Australia, that you guys can share with us?

Yes, I'll turn it over to Janine McArdle, who's our President of Kitimat LNG and Head of our LNG Gas Monetization.

In Australia, on our Wheatstone project, we're continuing to finalize our sales and purchase agreement with the buyers that we initially announced with HOA. And under Kitimat, we are talking to several different players in advancing those discussions.

Your next question comes from the line of Pearce Hammond of Simmons. Pearce Hammond - Simmons & Company International: Thank you for taking my questions. The first is a follow-up to the previous question on Kitimat. What is the timing that we might hear something on these off-take agreements?

We're in discussions right now. We hope over the next several months to make some further announcements. But as you know, these negotiations take a little bit of time. But there is a lot of interest at this moment. Pearce Hammond - Simmons & Company International: And then switching gears to North American service. What level of service cost inflation are you seeing right now? And in the Permian, for example, as well as in your central region?

Well, it's getting outrageous. [indiscernible] At some point, it's got to stop. Honestly, it's probably up 10%, 15% for the first quarter. Pearce Hammond - Simmons & Company International: And what were you planning when we went through your budget process on a percentage change year-over-year?

We don't plan. We try to beat them up as much as we can and beat them down. Pearce Hammond - Simmons & Company International: Okay. And then lastly, switching gears to Egypt. Recently, there was some sabotage on a gas pipeline to Israel. Does that negatively impact you guys?

No. I'll let Rod talk about that. That pipeline has been controversial in Egypt for years, and the gas sales agreement to Israel has been controversial for years. And it has no impact at all on our business. In fact, we have the opportunity to sell more gas, really, if we had it. We just don't have it right now. Rod, do you have a comment?

Well, this is the second explosion or fire on that pipeline in the last 60 days, both of which were probably terrorist acts. This pipeline, in the most recent one, was a metering skid on the line just before the line crosses into the Gaza waters and Ts off, it goes along the Sinai to Jordan. It's on the far east side of country. And all of our production, or gas production, is on the western desert side. It's probably 1,000 kilometers away from this location. All of our gas is sold into the national grid to the government in the west side of the delta. Also perhaps some of our molecules after we fiscalize our gas. The government may take those molecules and put them into that pipeline, but we have no direct association with that gas flow. Pearce Hammond - Simmons & Company International: Great. And then final question. And, Steve, this is a hard question, but at as it relates to Egypt, I think the former oil minister has been detained in like house arrest or whatnot. When do you think you'll get some clarity on the political situation in Egypt? Is it post these elections coming up in the fall? Or what's sort of your read of the tea leaves right now?

Well, there's not unlike any change in government. The previous government, whether it was ministers or prime ministers -- have to answer to the people that are in power now. That doesn't say they did anything wrong, or they did do something wrong, it's just the fact that they have to answer to them. In terms of our situation in Egypt, frankly, we have probably the best petroleum minister we've ever had, who used to be the Chairman of Khalda, was then the Chairman of EGPC and now the minister of petroleum for Egypt. His name is Abdoul Ghurab, and been in the business for 25 years, worked for GAPCO [ph] , which is the Amico-Lamico [ph]. We really don't find a lot of problems with the ministry, what we -- or even concerns, what we are going to run into here not too long from now is that we're going to have to take things to parliament, because most of these things come under parliamentary agreements for new acreage, for new gas contracts, et cetera, it has to be approved by parliament. The first order of business will, I think is supposed to be in September, they're going to have parliamentary elections, which is historically when they have them anyway. And then the ruling council has indicated that they will have a presidential election by the end of the year. So obviously, both of those are important. Frankly, the parliamentary elections are as important or more important than the presidential elections, at least in terms of having government start getting back to work. Pearce Hammond - Simmons & Company International: Right. Well, that's very helpful. I appreciate the color there.

Your next question comes from the line of John Herrlin of Societe Generale.

I got a bunch of different questions. In terms to the U.S. CapEx increase, how would you split it between, say, drilling and workover activities? Even or more skewed to drilling?

Yes, because I will tell you generally, workover projects are the highest rate of return projects, and we've become redundant so -- but we're looking for rate of return, and workover recompletions is the highest rate of return projects you can do. So the incremental capital is, pretty much with few exceptions, is all going to be on the drilling side.

Because the workovers would already be embedded in the capital.

Yes. It would already be embedded in the capital.

Okay, that's fine. With Egypt and the Paleozoic play, what's the aerial extent?

Currently, the extent of the play is unknown because we have this limited number of wellbores poked into it. The initial field also need an appraisal to be drilled, but it appears to be of the same size structure that we have placed our seismic interpretation that we've seen in other parts of the Faghur Basin. It just happens to be -- it appears to be an extension of the Faghur Basin's structural trend in the Siwa concession.

Okay. With Zola, when will you plan your next delineation well?

We have yet to formulate because we have just moved the rig off there 48 hours ago, so we have not had an opportunity yet with our partners to develop a plan of development going forward. It's hard to say if we'll be able to, on a rig line, to get the first appraisal in, in 2011. Although I'd say more likely, probably in 2012.

I might interject here. The important thing about Zola, I can't -- with Wheatstone and wherever that pipeline is coming down from the Julimar-Brunello, if you could look at a map, and it came back down to the western edge of Australia, we really have a real potential to be able to drill a lot of gas wells and take a lot of gas out of there for a long period of time now, where before we got into Wheatstone, we really didn't have that avenue. So the size of the field itself, or the discovery itself, it's a big synergy, all of that together.

Okay. With Horn river -- thanks, Steve. With Horn River, my next question, given the higher likely breakeven thresholds in terms of the infrastructure, you got liquefaction, the pipeline, et cetera, would you give up an equity stake in production to the purchasers like you're seeing with other deals?

Well, I think what you're seeing around the world is that the LNG buyers, whether it be TEPCO or KOGAS or the Chinese companies or the Malaysians, all of them like to have the integration of the upstream and downstream. And the upstream portion is much smaller than the offtake. But in terms of actually being in it, yes, I would anticipate in the end that, that this would have to be a wraparound in a deal like this, just like it is in Wheatstone.

Okay. With the Cook Inlet, is this going to be an AVO [ph] gain?

Is what?

I don't believe so. I think it's principally going to be the delineation of some very large untested structures that we currently see on some of the existing seismic.

If we look at a craning curves for reserves, and this is part of our New Ventures group, the information that they've put in the model when they were talking about whether should we be in the Cook Inlet, if you look at what happened to the wells in the Cook Inlet, they reduced significantly after Prudhoe Bay was found. And as soon as Prudhoe Bay was found, the number of wells drilled and the discoveries in Cook Inlet -- and our philosophy is, because there's very, very little 3D seismic sets over -- an old 3D, even at that, the existing fields that are there, is that people started -- they looked north toward Prudhoe Bay and started looking for bigger reserves up there. Honestly, I'm very excited about it. I mean, we haven't drilled a well there yet we got 300,00 acres, and we're getting ready to shoot some seismic. But it's got some real potential. It's a fun place to look.

Okay. Just last one for me. With the Granite Wash, are we talking about staggered co-mingled wells in terms of the completions? It sounded like you did once, then you wait a while, then you did the other? Or is this something you can bring on simultaneously in terms of the co-mingling?

No, you complete one, and draw down a little bit, and then come back. Do you mean in terms of the 2 zones together?

Right, exactly.

I mean, you will eventually co-mingle. I know it's just rehab now, but you take a little bit of time, and co-mingle and put them together.

Your next question comes from the line of Dan Morrison of Global Hunter.

A quick follow-up on the dual laterals in the Granite Wash, do you have any specific plans to try that in the Permian this year?

Probably not in the Permian this year. The Permian is at a much less advanced stage of horizontal exploitation compared to what we see in Oklahoma and in Texas the last couple of years, the Granite Wash. There, we still have a lot of vertical drilling, and we're beginning to pick -- it's the start of just drilling horizontal wells in some of these conventional reservoirs. So it's entirely possible. The geology is not exactly the same, but it could lend itself to an application in some parts of the basin in the future.

And in the Permian still, could you kind of rank the different plays you're chasing, or talk a little bit about allocation of capital? You said you were cranking up activity in the Yeso, but could you kind of work through some of the other plays that you're active in there?

Well, we're currently -- we have a very active horizontal drilling program on the central basin platform, and it's largely some of our old water flood units, like Lovelland [ph], Backalloy [ph] and Slaughter [ph] TXL-SU. We also have a CO2 program and a Roberts unit [ph] . We have a program in Southeast New Mexico in the Munoz [ph] area, in the Drikard [ph], and of course the vertical program in the Midland Basin and our Yeso program on the outside, the west side of Midland Basin there the Empire/Yeso and Empire/Adlo [ph] units, or attacking Adlo, Yeso and Wolfbury. And of course, in the Midland Basin, our Deadwood program. So those are the principal areas we're active at the present time with our 23 rigs.

I think half of those rigs run, aren't they running in Deadwood? So that's probably...

Yes, probably even more than half. Just eyeballing the list.

So that's a big area for us?

And we'll do a play-by-play walkthrough on our Analyst Day on May 17.

Great, thanks. Deadwood's a Wolfbury [ph] project?

Yes, and first tusselman [ph].

Your next question comes from the line of Tony Montana of Diversified Capital. [Technical Difficulty]

There are no further questions at this time.

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