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Executives

Scott Sheffield - Chairman and Chief Executive Officer

Richard Dealy - Chief Financial Officer and Executive Vice President

Timothy Dove - President and Chief Operating Officer

Frank Hopkins - Vice President of Investor Relations

Analysts

Michael Hall

Brian Singer - Goldman Sachs Group Inc.

David Kistler - Simmons & Company International

Leo Mariani - RBC Capital Markets, LLC

Jessica lee - JP Morgan Chase & Co

Brian Corales - Howard Weil Incorporated

Gil Yang - BofA Merrill Lynch

Richard Tullis - Capital One Southcoast, Inc.

John Nelson - Macquarie Research

John Freeman - Raymond James & Associates, Inc.

Rehan Rashid - FBR Capital Markets & Co.

Pioneer Natural Resources (PXD) Q2 2011 Earnings Call August 4, 2011 11:00 AM ET

Operator

Well, good day, everyone, and welcome to today's Pioneer Natural Resources Second Quarter Conference Call. Joining us today will be Scott Sheffield, Chairman and Chief Executive Officer; Tim Dove, President and Chief Operating Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Vice President of Investor Relations.

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors then select Investor Presentations.

The company's comments today will include forward-looking statements made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation and in Pioneer's public filings made with the Securities and Exchange Commission.

As a reminder, today's conference is being recorded. And at this time, for opening remarks and introductions, I would like to turn the conference over to Pioneer's Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir.

Frank Hopkins

Good day, everyone, and thank you for joining us. I'm going to briefly go through the agenda for today's call. Scott's going to be up first. He'll provide the financial and operating highlights for the second quarter of 2011. He will then update you on the company's production outlook, capital program and cash flow forecast for 2011 through 2014. After Scott concludes his remarks, Tim's going to discuss our drilling results and plans for the Spraberry, Eagle Ford Shale and the Barnett Combo play. In addition, he'll summarize the significant benefits that Pioneer is generating from our vertical integration investments. After that, Rich will cover the second quarter financial highlights in more detail and then he'll provide earnings guidance for the third quarter. And after he completes that exercise, we'll go through your questions and open up the line accordingly. With that, I'll turn the call over to Scott.

Scott Sheffield

Thanks, Frank. Good morning. We're going to start out on Slide 3, the highlights. Pioneer had another tremendous quarter, with adjusted income of $115 million, or $0.94 per diluted share, significantly above consensus on the street, excludes losses from discontinued operations of $2 million, or just $0.01 a share, and excludes our mark-to-market gain derivates of $133 million, or about $1.10 per share.

In regard to productions, we're above midpoint at 119,000 barrels of oil equivalent per day. If it wasn't for the loss of 2,000 barrels a day, which we lost essentially all during the quarter in the Spraberry asset team, we would have been at the high end of guidance. That 2,000 barrels a day was primarily lost due to the fact that a large Permian producer with trucks called us up and had to move their trucks out to pick up their own crude. So it took us really about 3 months to bring the trucking fleet back up, find some other trucks, and pick up that crude.

What's interesting is that the Spraberry division is already up between 45,000 and 46,000s, so significantly up net per day equivalent with the first quarter average of 41,000. Then in addition, I've seen a couple of interesting comments from some analysts that Spraberry is still an execution story for Pioneer after being there about 30, 35 years. But if you go back on Slide 30 in the back, just over the last 12 months, we're up 28% production growth from 31,000 to 41,000 barrels a day. And if you add back the 2,000 barrels a day for the quarter, we would have been up 34% production growth just over the last 12 months. So it's basically -- and we're still not at up to full ramp up, which we'll be by adding another 10 rigs by the end of 2011.

Production for the entire company was up 7% for the first quarter of 2011, primary related to the growth in Spraberry, Eagle Ford and the Barnett Shale Combo play. We expect second half reduction of 10,000 barrels a day per quarter approximately, both in the third and fourth quarter, essentially all coming from the 3 areas. So we're essentially getting to full ramp up in Spraberry, getting close to our 45 rig count. Eagle Ford's going well and also the Barnett Shale Combo.

If you look back on Slide 30, the rest of our assets are pretty much exhibiting fairly flat production growth, which obviously, with our long reserve life, flat production on our other assets, spending minimal capital allows us to then have this type of significant growth. Our liquids-rich drilling programs, obviously, we're ramping up in our core-growth assets. We'll be going up to 45 rigs earlier than anticipated. We'll be starting them late third quarter going into the fourth quarter.

Our results, what's interesting from our Strawn, Atoka and Mississippian is getting better and better as we see, with potential to increase our EURs in the Spraberry up to 110,000 barrels of oil equivalent just from a combination of these zones. Eagle Ford's ramping up as expected. The Barnett Shale Combo program, we're starting to see several wells over the last few weeks exhibiting much better performance than our type curve.

Increasing 2012 production growth target from 18%-plus to 20%-plus with additional $200 million, and that we'll explain that, but that's primarily the additional rigs in going deeper, but it's pretty much all attributed to the growth in Spraberry that Tim will talk about. We're not including in those numbers results from the Atoka, the Mississippian or the horizontal wells in that increase at this point in time.

We extended our compounded annual growth rate of 18%-plus through 2014. In addition, Tim's going to go over some great detail our investment of about $440 million over the last 2 years into the service side on how much we're saving. Our savings will exceed over $450 million by year-end 2011. We'll continue to increase significantly with our vertical integration. A lot is coming from the hydraulic horsepower that we've added.

In fact, we've added another -- we've made a decision to add more fleets, primarily going into the Spraberry and primarily Eagle Ford. We're adding another $100 million this year. We're starting to get feedback -- but this equipment will probably come on by next summer in these areas and will save us a lot of higher third-party charges. In addition, we're starting to hear feedback that it's going to be a 2-year lag time, but there's so much equipment that's being added to shale plays around the world, most of it has to be sourced in both Canada and the U.S. market. So we are now back. People want new equipment. It's going to take 2 years to get it. So we're set up to execute our growth based on the amount of equipment that we have ordered. So this equipment will be coming in next summer.

In addition, we've added some significant derivative positions on oil, and before the recent fall about 2 to 3 weeks ago, we're up to 50% hedging. If you look back in our schedule, up to 50% oil hedged in 2013 and 25% in 2014, pretty much did 3-way callers, between $65 and $90, we get $90, and then we let it float between $90 and $130, and after $130, we give it away. So significant callers help protect the oil side of the business as it's growing of up to 60% over the next several years.

Going to Slide #4. In regard to our production growth, as I mentioned already, 2012 has increased primarily, all due to the Spraberry Trend area growth increasing, although that's coming from the Strawn and also coming from the increased rig count. We extended the annual production growth target through 2014, and our liquid production increasing up to 60% in 2014.

We are maintaining our guidance range of 125,000 to 130,000 barrels a day for the year. We expect to be at the lower-end, primarily due to the severe weather that we announced in first quarter and some unplanned third-party impacts, which you can see in a footnote that have already happened in the first and second quarter of 2011.

Going to Slide #5, our capital budget changes. We're increasing the drilling budget, again, as I've mentioned, from $1.6 billion to $1.8 billion. That's primarily due to the Spraberry deeper drilling and the success that we're seeing there. In addition to the 6 horizontal wells that we are drilling now, the first 4 are in the Tippett shale zone. And with the recent EOG announcement of their 600 barrel a day plus well and the approach well is the reason we've target the Tippett shale down to the South portion of our acreage with the next oil wells. Tim will talk more about that.

Increasing these tin rates a little bit earlier, about $50 million. Obviously, with the delay of our company-owned frac equipment, we had to go out and hire some third party fracture stimulation services, that was an increase. But what's interesting in our entire budget, we're only seeing about -- when you look at strictly just cost grid, we're only seeing about a $50 million increase, about 3% of our total budget, due to the service cost and pricing power. That reflects tremendous investment of $440 million that we made over the last 2 years, primarily into fracture stimulations.

I've talked about the fleet that will be coming on, the 2 fleets that will be coming on by mid next year already. Obviously, the benefits from increased capital spending allows us to increase our production growth target, again primarily from the Spraberry Trend area field As you can see, upping in those numbers from 52,000 to 56,000 to 54,000 to 59,000 barrels a day year next year. And also, the results from strong production, again, as I mentioned, we are increasing production. We are not adding at this time results from the Atoka, the Mississippian and the 6 horizontal wells that we see.

Again, vertical integration. Obviously, this equipment that we'll be adding is essentially is going to be saving us about $80 million a year. So probably, about 1 year payout, around 1 year payout in this equipment.

Going into Slide #6, our operating cash flow. Again, we see operating cash flow about $1.5 billion, and using about $600 million of Tunisia sale proceeds. That will leave us about $200 million of Tunisia sale proceeds, which we'll be using to fund in addition to the cash flow next year for the 2012 CapEx.

Looking at Slide #7. You can see the significant ramp up in cash flow based on the recent strip, going from $1.5 billion up to $3.1 billion, we'll be doubling over the next 4 years. 30% compounded growth rate from 2010 to 2014. 2012, with the CapEx, expected to be roughly $2.2 billion, we'll be spending the $200 million of Tunisia proceeds, and the $2 billion of cash flow, going into '13 and '14 we'll be essentially spending -- the CapEx will be about the numbers that we see in our cash flow.

Investment highlights. Again, Pioneer with over 20,000 liquids-rich drilling locations in 3 key areas. The acceleration in our Spraberry and Eagle Ford areas starting to perform as we have seen Spraberry growth significantly over the last 12 months, Eagle Ford just now taking off. Again, the Tunisia sale, tremendous opportunity for us, allows us to be able to accelerate over the last few months. Again, having one of the highest compounded annual growth rates for the top 10 independents in the U.S. And then also with cash flow growth of 30-plus percent.

Vertical integration has been a much better benefit than we ever imagined. The decisions we made back in 2009 to buy into those businesses, we're seeing tremendous returns that allow us to keep CapEx down significantly over the next several years.

In addition, lastly, the strong balance sheet of debt-to-book of about 31%. Let me turn it over to Tim, to get into the assets.

Timothy Dove

Thanks, Scott. I'll start here on Slide 9 where I'll be giving you an update on the Spraberry Trend area where, as many people know, we're the dominant player, and we're the largest driller, the largest acreage holder and the largest producer, which also makes us one of the largest drillers in the Permian Basin. What's happening in this field, of course, is we're the dominant player, but it's a big field, which is continuing to get bigger as a result of all of our activities. And as you turn to Slide 10, a key reason for that is our continuing program of well deepenings. And as we continue the program, it gives us confidence that we'll have the opportunity to add significant additional EURs to future wells. The table we show below gives a little bit of detail on the data that we're collecting from these well deepenings. And we're finding very significant positive results. So for instance, we've already drilled 85 Strawn wells. The numbers shown to the right show the cost of those wells and peak rates, as well as potential EUR. In the case of the Strawn, it's something like 20,000 to 40,000 BOE, and it's prospective of about 40% of our acreage. And about 25% of the wells we're drilling this year have a completion in the Strawn. And what we're doing, of course, in this case is we're beginning the process of immediately commingling the Strawn with the upper zones because we have enough data at this point with the Strawn wells we drilled to understand exactly what their contribution is. New data coming in, though, on the Atoka and Mississippian is shown in the next couple of slides. We've now completed 2 wells in the Atoka. There's significant cost range shown there, and the way to explain that is, if we're at the top end of the range, say, $750,000, that's in areas where we would be drilling deeper to the Atoka. And in that case, we need an intermediate string and casing to be added, and in a lot of cases, we have to use a CO2 frac. The lower-end of the range, which will be about 50% of the wells, we can deepen the well to the Atoka for something like $250,000, that's where we do not need that intermediate string of casing and where we can use water fracs.

In any case, what you see about the Atoka is a significant contribution of 50,000 to 70,000 BOE, and it’s prospective, and it's somewhere to the -- in the neighborhood of 1/4 to 1/2 of our acreage. Mississippian, we've just completed our first well in the Mississippian. It's a zone which is currently testing and currently IP-ed at 105,000 BOE -- 105 BOE per day. We think the Mississippian can contribute 15,000 to 13,000 BOE where it works, relative in lower percentage of our acreage to the North, something like 10% to 20%. I circled the Strawn and Atoka top end of the ranges to focus on the fact that in the areas where we have Strawn and Atoka, we have the possibility to add up another 110,000 BOEs to our EURs from that deeper drilling. Realizing in most of the central areas of our acreage, the Strawn and Atoka are present while the Mississippian generally is present to the North. In general, we would say do not have both Atoka and Mississippian present at the same time. So you cannot add this table up. It depends on where you are drilling. But as you can see in the green circle that I've shown, a substantial potential for additions of EUR. And the drilling continues. We'll be testing several more Atoka wells this year, and then after testing those wells, we'll commingle them with the upper zones. In the case of the Mississippian 10 more wells to be drilled this year, a total of 24, as we continue the process of testing the play. So the deepenings area important contributor, I think, to future EUR adds and production adds in this field as we learn more. We have a substantial amount of offset data from other operators as to what these Atoka and Mississippian wells have done in the area. That's why we have a lot of confidence in their ability to also add pretty significant EUR.

Going to Slide 11 on the horizontal program. As we've already discussed before, we've drilled 2 wells, the second of which was drilled in the lower Wolfcamp. That was the well we discussed last quarter that, at that time, only had a few days of production. We ultimately IP-ed that well at about 220 BOE per day. We're continuing, as Scott has already discussed, a substantial horizontal program with 1 rig, 6 total wells by of the year, the first 4 in the Middle Wolfcamp Tippett shale that Scott mentioned, and a couple of more in the Jo Mill, which is a Middle Spraberry section. So we're going to continue this program through the rest of the year. The first of those wells is actually drilling. It's going to have a 6,000-foot lateral, 30-stage completion. So we'll continue to watch results from our R&D program to determine if there are horizontal drilling applications that can enhance the already excellent economics of our extensive vertical well program.

Okay, turning to Slide 12. As for production, it's really all about putting wells on production, and we discussed that in the last quarterly call. We accomplished our goal in the second quarter. We put 146 wells on production. And you can see in the slide, we've got a substantial amount of wells to be put on production significantly higher in the third quarter and the fourth quarter, and that gives us confidence in our production forecast. We will be adding the seventh frac fleet in the Permian Basin in the fourth quarter. That's a Pioneer-owned fleet. And that puts us back to our stated goal of being somewhere in the neighborhood of 2/3 vertically integrated when it comes to pumping services in our key areas.

As to the rig count, Scott has already alluded to the fact that we will be bringing in the rigs earlier than anticipated. All of our prior guidance have 45 rigs beginning January 1. We're bringing in something in the neighborhood of 1/4 earlier than planned. Of course, as we drill the wells during the fourth quarter with the additional rigs, that will have very minimal impact to 2011 production because of the time it takes to put the wells on production. However, it's going to have a big positive effect on 2012 production, and that's shown in more detail on Slide 13.

Scott has already alluded to the fact that the truck fleet issues were pretty significant during the second quarter. That was both with regard to shortages of crude oil hauling trucks as well -- and really, to a lesser extent, water hauling -- that led to about a 2,000-barrel-a-day shut-ins or inventory builds, as we're waiting on trucks. But as has been the case with all of our vertical integration initiatives, we're tackling that problem, and I think we have it solved, and the way we're going to do that is to, on the one hand, add our own water hauling trucks, and then we're adding a significant number of third-party oil trucks as well as new pipeline installations that will then relieve the need for more trucks. And in fact, if you look at the truck count, this is the oil hauling truck count in June, they were working on Pioneer wells, we had about 22 trucks hauling oil for us. We've now increased that to 35 by September, or a 60% increase. And we believe, essentially, by virtue of the actions we've taken, we've relieved this issue as of this month.

We also have several more trucks under contract for next year, several thousand barrels a day, somewhere in the neighborhood of 5,000 to 8,000 barrels a day of new gathering pipelines next year, and all of this will serve to reduce pressure on the need for crude oil hauling trucks. Current production, Scott said this earlier, but it's about 46,000 barrels a day in the Spraberry Trend area for us. That gives us pretty good confidence that our third quarter number looks good. If you take a look at the increment in 2012, by adding the rigs earlier in 2011, it's pretty substantial. So the 2012 guidance we had last quarter for Permian was 52,000 to 56,000 BOE per day. By adding those 10 rigs earlier, we can jump that to 54,000 to 59,000 barrels a per day, which has a big impact in terms of increasing the overall company rate of growth to 20%-plus for 2012.

Our average well cost for this year is still in the neighborhood of $1.5 million, $1.55 million, still a very strong rate of return, and it has a lot to do with our vertical integration that I'll talk more about in a minute.

I'll wind up the discussions on Permian in discussing our 20-acre program. We've drilled 24 wells since 2010 with very good results, encouraging results that indicate that the wells are generating EURs above our old traditional 110,000 BOE-type curve, and we'll be drilling another 10 to 20 by year end. But the 20-acre drilling by which we're deepening is, particularly in the Wolfcamp, are basically offsetting depletion effects by down spacing.

In the waterflood, we see continual increases in the number of wells that are actually increasing oil production as a result of the effects of the water injection, and the overall curve is flattening when it would otherwise be on a significant decline. That's indicative of the zone that's under water flow, the upper Spraberry zones, substantially increasing production. And I think shortly, we'll be giving you some information exactly how much we think it is increasing, but very positive results so far on the waterflood.

Okay, turning to Eagle Ford Shale, that's Slide 14. The Eagle Ford shale assets are hitting their stride. As planned, we're running 12 rigs. The average lateral length of the wells is now up to about 5,500 feet. The economics are quite outstanding as we've always discussed, owing to the rich condensate and generally liquid-rich nature of these wells. Well performance looks very good. We're seeing very good performance in Dewitt County, offsetting Black Hawk. One thing we're doing, as we discussed in the last call, is to push the envelope with regard to the use of white sand as a proppant. We have already stimulated 10 wells, and the performance of the wells looked very good and very similar to the direct offset wells where we used ceramics for the proppant. So the idea this year is about 30% of our wells this year, we'll be using white sand, and that's the number also planned for next year, 2012, about 30% of the wells. And importantly, that reduces the cost of the wells, something like $700,000 per well, which is very significant, if you look at the future drilling campaign. Infrastructure build-out continues. We now have 6 of our central gas processing facilities completed. A seventh will be completed by the end of this quarter and eight in the next quarter. So we are really ahead of the game when it comes to build-out of infrastructure. And the result as you see on Slide 15 is the ability to put more wells on production. We've met our goal in the second quarter of putting wells on production in the Eagle Ford. We put 18 wells on production. That's reflecting the frac bank being significantly reduced as well. The frac banks starting the second quarter was 22 or 23 wells, now it is 11 at the end of the second quarter, which is basically our minimum run rate, which is one -- basically one well per rig. But you can see, as we bring the 2 new CGPs online this quarter, we have a substantial ability to add a lot more wells to production. And in addition to that, we'll see a similar ability to do that as we get into the fourth quarter. So this area is going to be ramping up dramatically as shown on Slide 16, with the crude oil production well count increasing, third quarter should see a significant increase as shown on the slide, up to 14,000 to 17,000 BOE per day.

And then as you look forward, of course, in the next several years, this is an area of continued drilling, substantial acceleration of rig count. You can see we're going to 14 rigs next year. Those 14 rigs are all under contract. And then 16 rigs and 19 rigs looking forward.

On Slide 17, the Barnett Shale Combo play continues to show excellent results and in fact, better results as time's gone on. We are now in the process of actually acquiring new 3-D seismic to optimize our drilling locations. We still have the 2 rigs running. We anticipate going to 4 rigs next year. Importantly also, we've added our own company -- our own frac fleet during the second quarter. Again, getting to where we're heavily dependent upon our Pioneer frac fleets as opposed to necessarily going outside. And the reason for that, I'll show you in a couple of slides, as to the cost savings related to Pioneer services and Pioneer pumping.

The results in Barnett, though, are going to be increasing as well, as shown on Slide 18, as we begin the process of getting more wells on production. That's something in the neighborhood of 4,000 to 6,000 BOE per day this quarter, and growing as we increase the rig count in the next several years to 4 rigs at a minimum.

Okay. As to Slide 19, this is some data to give you some views as to what our total fleet capacity is today. In fact, we have 6 frac fleets working in our 3 key areas today, going to 8 by the end of the year. That will result in, as Scott has already mentioned, about $440 million cumulative investment, and will generate the ability for us to have 225,000 horsepower. You can see the photo of Pioneer Green. This is what we see all over our areas, Pioneer Green. We're proud of all the people who work in that group. And according to third-party analyst reports, that makes Pioneer the #15 company among all North American pumping services companies in terms of horsepower.

And Slide 20, kind of gives the bottom line on this vertical integration. This is the first time we've disclosed this information in this kind of detail. But the way you can read this is, the number of frac fleets working in each area and then the number by the end of the year. What I'm going to be talking about is end of year run rates because we will incorporate the fact we have 2 more frac fleets coming in this year. You can see the savings per well, very substantial. For instance, you save $1.7 million on the Eagle Ford wells by frac-ing our own wells. Now that -- the important note to be made there is where we're comparing the cost of Pioneer pumping the well versus an outside party is related to longer-term third-party contract rates. These are not spot rates, which are dramatically higher. But if we simply compare it to longer-term contract rates for pumping services, we can see that we generate substantial savings in the neighborhood of $460 million on an annual run rate basis. And so what that means is, as for all this investment, we'll have payment in less than 1 year as compared to doing third-party longer-term arrangements. As I mentioned, if we were to use spot rates, that would be substantially higher. And in fact, if we use current spot rates across the board for these 3 areas, our current savings run rate would be $715 million, 7 months pay up. So you can see the benefits of this are really coming in to roost, and I think they'll continue as long as we're in a tight pumping services market. So with that, I'll pass it over to Rich for his discussion of the second quarter financials and third quarter outlook.

Richard Dealy

Thanks, Tim. I'm going to start on Slide 21. As Scott mentioned before, net income attributable to common stockholders is $246 million, or $2.03 per diluted share. That did include unrealized mark-to-market derivative gains of $133 million after-tax, or $1.10 per diluted share, and a loss on discontinued operations related to our Tunisia post-closing adjustments of $2 million or $0.01. So adjusting for those 2 items, income was $115 million, or $0.94 per diluted share.

Looking at the bottom of the slide, where we compare our -- show our results compared to our guidance we came out in the second quarter, you'll see that each of the items within -- came in within guidance or in the positive side of the guidance with the exception of the current taxes, which were slightly higher because of South Africa, Texas being a little bit higher than we anticipated as we came into the quarter.

Turning to Slide 22, talking about price realizations. At the top, where you can see our realized prices, which exclude any impacts from volumetric production payments or derivatives. You can see that oil prices were up to $98.50, or 10% relative to the first quarter. NGL prices were up 14% to $48.16 in the second quarter as compared to the first quarter, and then gas prices were up 4% to $4.31. So commodity prices helped the company improve our margins during the second quarter. On the bottom of this slide, you can see the impact of volumetric production payments and derivatives, and how those affected our overall realizations. So it's there for your information. Probably, a couple of things worth noting, the volumetric production payments, as many of you recall, ended into 2012, so we'll pick up an extra 4,000 barrels a day of production when those run off, and then the derivatives, including our price impacts for oil, run off at the end of this year and then that will be the end of the...

Turning to Slide 23. Talking about production costs. For the second quarter, they were $12.82, down 4% from the first quarter. I think the important thing here is, if you look at the red part of those bars and base LOE for the past 5 quarters, if you adjust the fourth quarter to reflect the processing fee recovery we had, we're basically in the $7.70 to $7.90 range for the past 5 quarters. And so I think that's a real tribute to our asset teams, what -- they've done a great job managing our costs, especially in an inflationary environment with the run-up in oil prices.

Turning to Slide 24, and looking at our third quarter guidance. Production guidance for the third quarter is 125,000 to 131,000 BOEs per day. That range includes an estimated 4 weeks of lost South Africa production due to our wells being shut in currently as a result of unplanned outage at the GTL plant that takes our production. Current expectations are that the third-party operator will be able to get the plant back online sooner, but if the outage does extend beyond 4 weeks, we could have to update our guidance later in the quarter. You look at the rest of the items on this page, you'll see that they are very similar to what we've had in the past quarters and as our historical results have come in, so I'm not going to go through each one individually, but they're there for your modeling purposes.

So why don't I stop there, and we'll go ahead and open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And let's first go to Dave Kistler with Simmons and Company.

David Kistler - Simmons & Company International

Real quickly on the services side of things with the margins you guys are putting up, do you think about at some point spinning a piece of that off or monetizing a piece and putting that potential capital towards accelerating your drilling program even further?

Scott Sheffield

Not at this point. But Tim threw out a $715 million number. I guess if somebody offered $3.5 billion, we have to strongly consider it, 5x the $715 million number, but right now, with the savings that we have and the growth in it and the benefits we're seeing, we just don't see it, so.

Timothy Dove

Furthermore, Dave, we're still growing that asset base, right? We've got more fleets coming in, so we haven't built what we're going to finally own.

David Kistler - Simmons & Company International

Does that become ultimately an option for the business, or is this something you think you always want to have tucked underneath?

Scott Sheffield

We think with 20,000 locations -- and we're strong believers in the oil environment over the next several years that we just see the tightness of the hydraulic horsepower, as I mentioned right now, it's going to take 2 years to get new equipment. We just see it tight for several years, and the demand for the international shale plays are developing now, it's all coming out of the U.S. market, too, so it's going to be tight for a long time.

David Kistler - Simmons & Company International

Okay. And maybe following up on that a little bit in terms of you've shown very attractive production growth, so don't take this as something suggesting your growth isn't attractive, but when you start looking at production from South Africa and Alaska and your growth continues, this becomes smaller and smaller piece of the equation, do you look at those as vehicles to monetize and potentially make sure you can continue to live within cash flow and deliver the same kind of or better growth than you're already drawing out there.

Scott Sheffield

Yes, right now, South Africa, our contract runs out in late 2013. So the asset at this point in time in our modeling essentially goes away at that point in time. We do have upside for extending that contract, so there is a lot of reserves left in the ground, up to 2020, that we can produce it. So it's always a possibility. So at this point in time, we're only modeling to about September 2013. And then regarding Alaska, we're drilling 2 key wells, very important wells this coming winter. One's a deep test in the main producing zone out of Prudhoe Bay, near the shack. And then another well is a -- we're going to fracture stimulate this new Torok zone that -- we drilled 2 wells. They've been fairly good over the last 12 months. But we have not selectively frac-ed each zone like we do a plug and perf like in Eagle Ford or on the Spraberry horizontals. We're actually going to do that technique up there, get a much bigger frac, and we think the wells will come in much stronger. So those are really 2 key wells. And then hopefully, with that success, it will drive growth over several years, but it's always an option in regard to whether or not to look at divesting those 2 assets. But right now, we see one running out and one growing significantly over the next several years.

David Kistler - Simmons & Company International

I appreciate that color. One last, probably a little bit more micro, question. When you look at the Atoka interval that you guys are exploring or developing at this point, the cost metrics on that went down on the low-end. Can you talk a little bit about what drove that?

Scott Sheffield

Tim?

Timothy Dove

Yes. I think I mentioned this during the call. We've now determined that some of the areas where we have Atoka prospectivity are shallower, and then in that case, where it is shallower, we do not need that string of casing, intermediate string of casing that would be needed for deeper drilling. Some of the areas of the Atoka, you have a pretty clay-rich section, where you worry about swelling, where we have to do CO2 fracs. In other areas, we don't see as much clay content. And in that case, we can use water-based fracs, which are cheaper. So what you're seeing in the low end is those areas that are shallower and, as a result, are cheaper to complete them. That said, I think 50% of the acreage probably lies in each of those categories.

Operator

And from Goldman Sachs, let's go to Brian Singer.

Brian Singer - Goldman Sachs Group Inc.

Looking at the various guidance for 2012, it would seem like if we used the midpoint for the Spraberry, Barnett Combo and Eagle Ford and some normal course decline rate for some of the assets you may be a bit less focused on, it would imply a greater than 20% year-on-year increase. And I just wanted to see if there was anything specific in terms of more extensive declines or whether you were factoring any asset sales into end of 2012?

Scott Sheffield

No. First of all, we're using a plus number, 20%. And we're trying to be conservative. As you can see what happened to us, first quarter, the winter was much more severe weather. So you have no idea when you're going to have a severe weather, or any other type issues. So we try to, each year, come out with conservative numbers. But we are using a 20% plus number. I hope it's a lot better than 20%, but as you know, as we've seen, what's happened with unplanned outages in Alaska, with third-party delivery of water up there, with severe weather we had in the first quarter, it's always nice to be conservative.

Brian Singer - Goldman Sachs Group Inc.

And then shifting to the Eagle Ford. Can you just add a little bit more color on well performance and decline rates, how that's coming in relative to your type curve and the oil gas and NGL mix that you're seeing relative to your expectations.

Scott Sheffield

Yes. It really hasn't changed. We've been using 6 Bcf equivalent. I know we got several questions once Petrohawk increased their reserves. But obviously, it's nice to see people paying 23,000 per acre right next to our acreage, and what happened with the recent BHP transaction, just to highlight the value of our acreage. But we really haven't seen any changes with our original numbers that we came out probably 18 months ago, Brian. So still, we're focused pretty much on the liquids, height, more of the higher condensate than the lean. But most of the rigs now are focused on holding leases. And then we'll -- I think beginning in about 2014, we'll focus primarily on most -- assuming the ratios are still 20, 25:1, we'll focus more on the higher rich-condensate areas. So we really just haven't seen any change than we've originally come out with.

Operator

At RBC Capital Markets, let's go to Leo Mariani.

Leo Mariani - RBC Capital Markets, LLC

Hoping you guys could just talk about infrastructure in the Eagle Ford and your sort of crude oil transportation scenarios which you guys currently do. Are you seeing any bottleneck? Are you having to choke back your wells at all? And where are you guys selling your crude, and how is pricing working?

Timothy Dove

Yes, Leo. I think at this point in time, I'd say, we do not have any significant infrastructure issues in Eagle Ford shale when it comes to crude oil. We -- all that oil, of course, is being trucked. Since we were one of the early guys in there and in doing so, we're working on infrastructure before anyone else, we have all the trucks in hand that we need to move oil. So it's really not an issue. The discount for this type of material, though, is related to the fact it's so high gravity. So we tend to get $4 or $5 off WTI for the condensate, just because of its gravity.

Leo Mariani - RBC Capital Markets, LLC

Okay. And are you guys sending that to the cushing market, or are you able to get that to any of the Gulf Coast markets?

Timothy Dove

We're working on the possibility to do some barging with some of the other players who are putting that into place. But for right now, at least, it's all WTI-based.

Leo Mariani - RBC Capital Markets, LLC

Got you. Okay. And what are your sort of current well costs looking like in Eagle Ford right now?

Timothy Dove

Well, the blended well costs are still in the neighborhood of $7 million to $8 million. That said, as I mentioned earlier, when we were talking about the vertical integration business, we can drop those costs by I think it was $1.7 million. And so our internal numbers are a lot lower than this average, but this also incorporates the fact we have an outside frac fleet working for us as well at a higher rate.

Leo Mariani - RBC Capital Markets, LLC

Got you. So if I were to sort of do some quick math, that would seem to imply that maybe your internal well costs are sort of in that $500,000 range and maybe high 60s and external are kind of low-8s, is that about right?

Timothy Dove

Exactly right. You're good at math.

Leo Mariani - RBC Capital Markets, LLC

And can you guys give us a little bit more color about Alaska. I mean, the production's kind of stagnated there the past couple of quarters. I know you did have some downtime related to some maintenance and some water handling. Is that production expected to start to kick up here in the second half of the year? Just any color you have there would be great.

Timothy Dove

Well, I was going to just give more color on the details on it. But the main issue we're facing there, Leo, is related to water injection shortages. And this is -- as you know we take water from the other big operators up there, and we have contractual rights do so. But because of issues they've had from their infrastructure side, we've been severely limited on water injection. And every well on Alaska has water injection paired with it. So to give you an example, we at this rate, need something like 15,700 barrels a day of water. And we're significantly short of that in terms of what we're being supplied, something like 6,000 barrels a day. So cumulatively, what happens is, we don't have enough water to inject -- you're basically not properly sweeping the oil from the reservoir. And that's definitely what we're facing here. We're working on internal fixes to start generating our own water supply. We didn't think in advance of this project that was going to be required because the operator in question, we thought could deliver all the water we needed. We're simply finding that, that's not the case. So our production would be higher in this year, other than for the fact we're losing production related to this lack of water. Probably, 1,000 barrels a day at least in the first half of the year.

Leo Mariani - RBC Capital Markets, LLC

Okay. So in terms of you guys are obviously working on some solutions. Is that something we should expect by early next year, hopefully, something in play, and the volume start moving up? How should we think about the kind of production progression?

Timothy Dove

We're going to be drilling more wells as we speak, but I think our internal solution will not be able to get that done until the latter part of next year.

Operator

Up next, let's go to Rehan Rashid with FBR & Co.

Rehan Rashid - FBR Capital Markets & Co.

A quick few questions. One on Eagle Ford, the well cost, the $7 million to $8 million, does that include or exclude the benefit from using white sand?

Timothy Dove

Yes, that's a ceramic-based cost, Rehan. So it does not include the benefits of white sand.

Rehan Rashid - FBR Capital Markets & Co.

Perfect. On your reserved booking for year end, how do you expect all your PUDs to kind of play out given the success in Strawn and Atoka? Will you be able to incorporate this, this year?

Scott Sheffield

Yes. We see similar results to what we showed last year, basically, in our key areas, Barnett Combo, Spraberry and Eagle Ford based on our drilling activity. So it will take us probably, generally, the Strawn, we've got about 8 months of history now. So we'll see more bookings from the Strawn, probably not going to see a lot from Mississippian and Atoka yet.

Rehan Rashid - FBR Capital Markets & Co.

Got it. Okay. Barnett Shale Combo, well performance improving, could you give us some color on that? And also, the Spraberry Shale wells, Wolfcamp and both carbonate and shale, results are okay so far? Maybe some color on that as well. And that should be it.

Scott Sheffield

Yes. Barnett Shale Combo wells, they're averaging about 350 barrels a day. So it's about 30%, 40% higher than our type curve, our last few wells. So very, very positive there. So we're starting to see production ramp up fairly significantly in Barnett Combo play. You said the Spraberry Shale wells, I'm not sure -- we're still opening up all the shale zones in the Spraberry and the Wolfcamp intervals. So obviously we're seeing -- I don't know if Tim mentioned on the 20-acre drilling, too. We're still -- we're starting to see all these 20-acre wells creep up toward the 140,000 barrels of oil equivalent. If you recall, the offset 40 only opened up the conventional reservoirs that we drilled over the last 20, 30 years. And so we've done several wells, and they're holding -- we do not think we've made a statement they're going above 110 but they're getting closer to 140,000. So very, very positive results opening up another 15,000, 20,000 locations for us over the next several years, too. So I don't -- not sure what you refer to, but the Spraberry Shale wells.

Rehan Rashid - FBR Capital Markets & Co.

No, just the initial -- the horizontal wells, basically that are coming in.

Scott Sheffield

The horizontal wells. Yes, the -- Tim mentioned the lower -- we're the only ones that have been drilled in the bottom of the Wolfcamp, and that's the well that got up to about 220 barrels a day. And we have moved the next 4 wells to the Tippett shale, which is a Middle Wolfcamp zone, and so far, we're monitoring EOG's best wells over 600 barrels a day equivalent. Very, very economical and then Approach just announced in the last -- yesterday, well over 600 barrels a day equivalent. And our 4 wells are down in the southern part of the Spraberry Trend area, very close to these wells. And that's where the acreage, that several companies including Petrohawk and Forest and ConocoPhillips, and there's a lease sale coming up in September, and essentially, all university land has been put up in this area by some operators. So it'd be interesting to watch this lease sale up coming up next September out of Midland. But the focus is on this Tippett shale zone. So we're still encouraged, but we'll see after these next 4 wells.

Operator

Let's go to Brian Corales with Howard Weil.

Brian Corales - Howard Weil Incorporated

Just on the Spraberry, when you all drilled, do you all go all the way to the Mississippian in most wells and kind of see if it's there? Or how do you all progress on the drilling plan there?

Scott Sheffield

Yes, the -- we've got -- we would -- a lot of oil shale producers go to the Mississippian, some have gone to the Atoka, some have gone to the Strawn. We pretty much have it a mapped. And what we've been doing on the Strawn is basically, we take about -- it doesn't cost very much at all. We take about half our wells down to the Strawn with the completing about half of those wells so it has porosity. Then we'll go and complete. So it only takes us another maybe $20,000 to drill and take a peek. So insignificant. In the Atoka, we know exactly which area we're going to take the Atoka wells. We've only done 2 wells. We're 2 for 2 in the Atoka, and we're 1 for 1 in the Mississippian. So same approach. And if it overlaps -- where it overlaps in the Mississippian, if there's a Strawn, we'll produce the Mississippian for a while, come back up and test the Strawn and then we'll add the rest of the Wolfcamp Spraberry zones over time.

Brian Corales - Howard Weil Incorporated

Okay. Okay. And switching over to the Eagle Ford. I mean, kind of with all the -- it looks like infrastructure and you've got the completion crews locked in. I mean, what's the major risk? Or is there a risk to kind of the outline that you all put together over the next couple of years?

Scott Sheffield

We've tried to minimize -- I've always said commodity prices, but we're pretty much protected over the next 2 or 3 years. We have $80 floors and $90 floors over the next 3 years, '12, '13 and '14 on the crude side. We feel like we protected that. Tim and his team have done a -- Bill Hannes have done a great job in Eagle Ford with all of our major agreements with DCP, Enterprise and Copano. Everybody is cooperating. We're able to execute on getting our product to market. So at the Eagle Ford, then with our second frac crew coming in, and with the additional frac crew coming in, in 2012 and '13, which we can shift to Eagle Ford in '13, is that we essentially have everything taken care of in Eagle Ford.

Operator

At Wells Fargo, let's go to Michael Hall.

Michael Hall

Most of mine have been answered. I guess just a couple of quick ones. First, in the Permian, the Spraberry, you're talking 25% of wells being commingled this year into the Atoka. Any initial thoughts on what that looks like in 2012, and then maybe what percentage are also then possibly commingled to the deeper intervals as well for 2012?

Timothy Dove

Yes, I think you can probably look at, in the case of the Atoka, about 25% to 50% of our acreage is prospective. So I would say that it will take a substantial amount of our campaign as we continue to drill that out. But the total number of wells we have planned this year is 10 more. And we'll probably drill at least double that next year. So it hasn't really been developed in that level of detail yet, Michael, as to the exact drilling plan for Atoka. We're really sort drilling this first campaign to know the answer to that question.

Michael Hall

Got you. And then can you remind me kind of gas takeaway capacity in the Permian? Are there any infrastructure constraints there? And like the Nuiqsut [indiscernible] plant, is that full? To what extent do you have priority on that plant, and are you flaring any meaningful amount of gas on that?

Timothy Dove

I think what -- the situation for us is that we have equity ownership and gas processing facilities. And we've built recently a new plant in the Permian Basin that came on earlier this year. And we also are going to be reestablishing the processing from the plant that it replaced. So it will be really significantly increasing our capacity. So actually, gas processing capacity is simply not an issue. We also have ownership another plant to the north that's expanding. So what's happening is the gas processing facilities are being expanded in advance of the increase in production.

Michael Hall

Okay. And then do you have equity ownership? Do you typically have priority on those systems and in the...

Timothy Dove

Yes, absolutely. And it also has to do with the fact we have priority in getting our gas gathered as well. Because that's where the agreements line out. The processors in this case gather the gas, and so we're first priority in every way.

Michael Hall

Okay. Makes sense. And then just last one for me, any -- by chance willing to throw out any run rate in terms of, call it, July or current production after the trucking constraints have been alleviated?

Scott Sheffield

I already gave a run rate on Spraberry. It's been averaging, as I mentioned, it averaged 41,000 for the quarter. Second, it's already been averaging 45,000 to 46,000, so already up 4,000 to 5,000 barrels a day, Spraberry.

Operator

And our next question is from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

On the Spraberry trucking -- truck hauling issues, how much of the loss volume was shut in versus inventory builds?

Timothy Dove

About half of each, Gil.

Gil Yang - BofA Merrill Lynch

Okay. And the rate going to 45,000 to 46,000, how much of it is depletion of that inventory?

Timothy Dove

Say, 1,200 barrels a day. So we still are in the process of finalizing getting these trucks to finish the job.

Gil Yang - BofA Merrill Lynch

Okay. So you've been able to take the inventory sitting in tanks down, but you still haven't brought the trucks online?

Timothy Dove

Well, we're in the process. During this month, we'll have enough truck fleet to clear all that inventory and get all wells on production.

Gil Yang - BofA Merrill Lynch

I see. The inventory's still there because the trucks aren't available?

Timothy Dove

Well, they're just coming in, Gil. I mean, this is a process, and so therefore -- we probably have about 700 barrels a day that we'll increase from where we are today just by virtue of completing the truck fleet.

Gil Yang - BofA Merrill Lynch

Okay. Got you. Can you talk about, since Rich is there, was there any effect -- you raised the cash flow guidance for 2012, 2013. Was there any effect from different price sets used between the 2 different periods? I think the last one I saw was June and June pricing?

Richard Dealy

Yes, it's based on that. I can't remember what we were -- the June strip price deck was, but this one reflects in early August strip price deck. And so I'm sure there's an impact from that, and then plus the Spraberry production growth that's highlighted in the slide.

Gil Yang - BofA Merrill Lynch

But do you know -- you don't know what it is broken out between the price deck change and the Spraberry volume change?

Richard Dealy

No, we can get it for you, Gil. I just don't have that data here in front of me.

Gil Yang - BofA Merrill Lynch

Okay. Because when I look at the strips at the end of not knowing the exact timing, they don't look that different. Or do you think they are different?

Richard Dealy

I don't think they're clearly different. I think most of it -- excuse me -- is coming from the production, but I'm sure there's a contribution from both. I just don't know the exact mix.

Gil Yang - BofA Merrill Lynch

Okay. And then last question. With the waterflood project, could you just review for us, based on what you're seeing the what the lifting cost of that -- of those barrels are given the water injection, incorporating both maybe higher cost water because of the water issues in the area combined with the fact that your actually disposing of produced water, which saves you water hauling?

Timothy Dove

Yes. I mean, I think the costs on this is extremely low. And you hit the nail on the head there. What happens is, we're taking produced water, cleaning it up and re-injecting it. So we don't have to go dispose of it. So actually, in a waterflood project of the type we're talking about, very significant cost savings and very low capital, just for those 2 reasons.

Gil Yang - BofA Merrill Lynch

So the LOE is lower than your average February LOE?

Timothy Dove

Far lower.

Operator

Let's go to John Nelson with Macquarie.

John Nelson - Macquarie Research

I guess just a comment to some questions Brian asked, maybe in a different way. Your out-year Spraberry production guidance, still a bit conservative being a 45 rig program. I'm not sure if that has to do with longer drill times from deepening the wells, so I was just wondering if you can give an update on what the right blended average spud to spud we should be using going forward.

Timothy Dove

Right now, we're averaging about 1.7 wells per month per rig, so that's kind of a good rule of thumb for you.

John Nelson - Macquarie Research

And then, the Mississippian well tests, you said it was in the North, but what county was that in?

Scott Sheffield

Martin County.

John Nelson - Macquarie Research

I'm sorry, what was that?

Timothy Dove

Martin County.

Scott Sheffield

Yes, Midland and Martin are the 2 counties -- the most important for all 3 of those zones that we're going deeper in.

John Nelson - Macquarie Research

Okay. And then just last one. I know you talked about the land lease sale coming up in September. Do you guys think you'll be participating in that? Or are you just saying you will watch it for potentially high rate?

Scott Sheffield

Yes, the -- more for the interest level. The last lease sale, the acreage was going for about $3,000 per acre. So it'd be interesting to see what happens in this, but it's all been nominated. And we pretty much have 15% to 20% of our acreage down in this area already. So we're just -- allows us to watch. And most of it's held by production. So it allows us to watch the performance from the horizontal efforts by the other companies.

Operator

Raymond James, John Freeman has our next question.

John Freeman - Raymond James & Associates, Inc.

On the discussion on the white sand versus ceramic, obviously, sounds like so far some pretty clear the savings with not really giving up much on the performance. How much more would you need to see before you think about changing the well mix next year from 30%, sand versus ceramic?

Timothy Dove

Well, John, as you know, a lot of the deeper areas as we move South and East in that trend are going to require ceramics. And what we're going to be doing is pushing the envelope as hard as we can. The number anticipated for next year is about 30%. But I think probably, we could do a little bit more than that as we sort of edge out and continue the process of learning the impacts of using white sand. So I would say, it would probably be over 30%, but it was clear there's a substantial amount of the acreage we need ceramics.

John Freeman - Raymond James & Associates, Inc.

Right. That's helpful. And then one point of clarification in the release. When you all said, you forecasted what your frac sand requirements are through 2015, does that mean that you all have -- are working to secure that, you already have secured it?

Timothy Dove

All those are under contract, John. All of our sand needs for Permian are under contract.

John Freeman - Raymond James & Associates, Inc.

Through 2015. Okay.

Timothy Dove

That's right.

John Freeman - Raymond James & Associates, Inc.

Okay. And then just last question. Is there any gap at all that you all see in your current vertical integration model, like some business that you're not in right now, that you think you may want to add if you look out several years?

Timothy Dove

Tell you what, at this point in time, with our VI, we're pretty much got everything. We're close to having everything. There's certain things we don't want to get too much of because it's not something where we're worried about cost creep. But if you take a look at the bottom of Slide 19, you'll see that our VI stuff. It's got those pulling units. It's 23 pulling units. It's hundreds of frac tanks, several hot oilers, water trucks, BOPs. We just acquired a bunch of construction equipment to basically do much of our own dirt work, and we have a substantial number of fishing tools. That pretty much covers the gamut. We're not going to be 100% self sufficient on vertical integration, but in all of these areas, we realize there are substantial savings. We probably save $30 million a year just from those unit, those areas themselves, not counting the frac fleets and so on. So there's a substantial savings by doing a lot of this work ourselves. But from here, I think we'll look at just piecemeal, picking up additional equipment where it makes sense.

Richard Dealy

Also, John, we're budgeting less than $50 million for VI next year, so you'll see it come down from $300 million to less than $50 million going into 2012.

John Freeman - Raymond James & Associates, Inc.

You know it's gotten pretty big when you all can just refer to it as VI, right?

Scott Sheffield

Yes.

Timothy Dove

Let's call it a major acronym. I expect to see that in your report, John.

Operator

Let's go on to Sven Del Pozzo with IHS Herold.

Sven Del Pozzo

Would you care to comment on the Eagle Ford Shale production currently?

Timothy Dove

No, obviously, we have a range of 14 to 17. We feel confident we'll have that range, but it's increasing daily. So the only reason we gave out the Spraberry number is just to show a couple of people who are focused on the fact that we haven't been executing on the Spraberry and also talk about the fact that we had the truck issue, and the truck issue has been solved. But we're not going to be an habit of giving up on the time production of all of our assets. But it's [indiscernible]. And our guidance is 14 to 17. So it will be up substantially. So the number of wells, you can sort of take our average production, look at the number of wells that are coming on, and that pretty much gives you the information.

Sven Del Pozzo

Okay. Do you have... are your wells confidential, like the most recent wells, like -- can we get well data for them? On the Eagle Ford, still?

Scott Sheffield

Yes. You can go to the Texas Railroad Commission. We have to file with them, and it's always a couple of months behind, but they can always go to the Texas Railroad Commission and get public data. Like some of the other services pick it up later than that, but obviously, the best way is to go to Texas Railroad Commission.

Sven Del Pozzo

Okay. Now after you make your Midstream investments in the Eagle Ford, can we associate a number of wells that, in the Eagle Ford, that the Midstream investments could support?

Timothy Dove

Well, it's built to support every single well.

Sven Del Pozzo

And the timing of that would be -- you're always going to be ahead on your Midstream capacity versus your production?

Timothy Dove

Well, the CGPs, as you know, we have 2 more coming on this year, but those are always built, in a throughput capacity sense, much higher than the production, so as to make sure we have adequate room for wells. And also they're modularly designed so that they can be easily expanded or contracted in an area where you're done doing the drilling. So the fact is, we'll be done with the build-out of all those facilities in 2013 or so, and then we can expand past that point.

Sven Del Pozzo

Okay. Could you give me an idea of your water sourcing for the Eagle Ford frac job?

Timothy Dove

Yes, water down there comes from several different sources. We get water from some shallow aquifers, and in addition to which, we're also buying water from surface owners. And in fact, from various surface owners in the area where mineral rights allow the owner to be able to sell the water. And so it comes from a wide variety of different suppliers including some river water as well. So it's really, in this case, it's a lot of different ways that we're sourcing water.

Sven Del Pozzo

Okay. Spraberry Trend, just from your press release when you're talking about the Strawn and Atoka both being present in certain areas. I mean, it sounds like the incremental 110,000 per BOE, if you compare that to your old Spraberry type curve, say prior to 12/31/10, I mean, it would basically double that, I'm thinking -- correct me if I'm wrong. And what's the -- from a top-down basis, what's the completed well cost for in total for a well like that?

Timothy Dove

Well, go ahead, Scott.

Scott Sheffield

Yes, that's -- yes, you're right on the -- we could have a 220,000 barrel well. But remember, the 110,000 is up to 140,000 now, based on the fact that we're opening shale zones in the Wolfcamp. So you could get a 140,000 and up to a successful Strawn, Atoka wells. So you could get up to 250,000 potential on a lot of our acreage, so that's the plus sign.

Sven Del Pozzo

And from a -- what should I be thinking for a completed well cost for a well like that?

Scott Sheffield

You could get as high -- I'm more confident that the team will not spend $750,000 on Atoka well. So I think the water frac will work, then also they're going to experiment with running no intermediate casing. But our initial wells, we did spend $750,000 for the Atoka. So the Strawn is very little. So it could be a range of up to $2 million, is where I think the ballpark is going to be after drilling several wells.

Timothy Dove

And that would be the average well costs, and that does not consider VI. I mean, to the extent we're using our own facilities, the number's substantially lower than that. I think we've already publicized that, that VI can produce the well cost in Permian something like $500,000 per well.

Scott Sheffield

Sven, would you mind calling us back, we have some more [indiscernible] call us back, we'll be happy to...

Sven Del Pozzo

No problem.

Operator

Our question now from Joseph Allman with JP Morgan.

Jessica lee - JP Morgan Chase & Co

This is Jessica Lee for Joe Allman. I have a really quick question on your Eagle Ford wet gas takeaway capacity. What is it currently? And do you project that -- you project growing going forward?

Richard Dealy

I'll have to get back to you on that, Jessica. We have substantial capacity to take gas out of the area, and we're actually tied up with 3 different contracted parties, as Scott had mentioned. I just don't have the number off the top of my head. We can get that for you. And so please call back our IR. We can get you that detail.

Operator

And our final question at this time is Richard Tullis, Capital One Southcoast.

Richard Tullis - Capital One Southcoast, Inc.

Just a couple of quick ones. I apologize if you went over this already. Busy morning. I saw you added a small amount of acreage in the Barnett Combo play. What's the ability there to materially add to that? Is it all pretty much leased up around you at this point?

Scott Sheffield

We're hoping to get up to about 100,000 acres over the next 18 months. So we're also -- we've got a program, some of our acreage, we only own maybe 75% of a drilling location. So we're picking up the other 25%, too. And so we see hopefully getting up to about 100,000 acres to give us 1,000 locations.

Richard Tullis - Capital One Southcoast, Inc.

All right. And just the last one, I know you plan to do a couple of more of the horizontals in the Permian. When do you think you'd have another well results update on that?

Scott Sheffield

We're just telling -- Tim mentioned that we are drilling our first Tippett shale well. It's in the lateral now. We're going to drill 4 of those over the next several months, so they won't be frac-ed probably for another 4 to 6 weeks. So we will give updates over time in our horizontal program.

Richard Tullis - Capital One Southcoast, Inc.

Okay. So you won't wait until you have all the wells down?

Scott Sheffield

We could. I mean -- but I just don't know at this point in time.

Operator

With no further questions, I'll turn the conference back over to the company for any additional or closing remarks.

Scott Sheffield

Again, thanks. We appreciate everybody taking the time. I know it's a busy day for everyone, and look forward to seeing everybody the next quarter. So thank you.

Operator

And at this time, we conclude our conference call. Thank you very much for your participation. Have a great day.

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