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Executives

Frank E. Hopkins - Vice President of Investor Relations

Timothy L. Dove - President and Chief Operating Officer

Richard P. Dealy - Chief Financial Officer and Executive Vice President

Scott D. Sheffield - Chairman and Chief Executive Officer

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Rehan Rashid - FBR Capital Markets & Co., Research Division

John Freeman - Raymond James & Associates, Inc., Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Will Green - Stephens Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Unknown Analyst -

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

David W. Kistler - Simmons & Company International, Research Division

Pioneer Natural Resources (PXD) Q3 2011 Earnings Call November 2, 2011 12:00 PM ET

Operator

Welcome to the Pioneer Natural Resources Third 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, Senior 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. A replay of the webcast will be archived on the Internet site through November 23. Today's conference will be recorded.

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 and 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. At this time, for opening remarks and introduction, I would like to turn the call over to Pioneer's Senior Vice President of Investor Relations, Frank Hopkins. Please go ahead, sir

Frank E. Hopkins

Good day, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott will be the first speaker. He'll provide the financial and operating highlights for the third quarter of 2011, another strong quarter for Pioneer. He'll then update you on the company's production outlook for 2014 and our recent drilling success in the horizontal Wolfcamp shale play. After Scott concludes his remarks, Tim will discuss our drilling results and plans for the Spraberry, the Eagle Ford Shale and the Barnett Shale Combo Play. Rich will then cover the third quarter financials in more detail and provide earnings guidance for the fourth quarter. After that, we'll open up the call for your questions. So with that, I'll turn the call over to Scott.

Scott D. Sheffield

Thanks, Frank, and good morning or I guess we're moving into the afternoon now with earnings calls in some places. I'll start on highlights.

Slide #3. Again, we had a tremendous quarter of adjusted income, $160 million or $1.35 per share. That does exclude our mark-to-market of $191 million or $1.60 per share. What's more important is that production is above midpoint on our guidance of 128,000 barrels of oil equivalent per day. Above 9,000 barrels a day, that's an 8% increase versus second quarter. Oil is also up 17%. On the oil side, obviously, it's coming from Spraberry, the Eagle Ford and the Barnett Shale Combo Play, our 3 big growth play. This follows a production increase of 7,000 barrels a day from first quarter to second quarter. And also with our guidance going into fourth quarter, we expect production growth of 10,000 barrels a day equivalent over the next -- and I think we're already up. As Tim goes over each of our 3 key growth areas based on our current rates, we're already up 11,000 barrels a day going in those 3 areas going into late October and early November.

We had 19% U.S. production growth from third quarter '10 to third quarter in 2011. We expect U.S. production growth of 22% from 2011 to 2012. We're going to continue going into next year, focus on U.S. production growth as our last international asset, South Africa, next year, will be down below 2% of our production and 2013 down below 1% of our production.

Going into each of our key assets just summarizing equipment before Tim goes into more detail. All of our liquids-rich plays are exhibiting strong, very, very strong well performance. We averaged 38 rigs in the Spraberry during the third quarter. We continue to see tremendous success in the deepening intervals including the Strawn, the Atoka and the Mississippian. Tim will go into more great detail. But it's got the potential to add up to 110,000 barrels of oil equivalent in each of those key areas. And that's pretty much most of our deeper vertical drilling is in the top 800% -- 80% of our acreage in 900,000 acres and that's where we're getting the best returns with the deeper drilling and that's where most of our rigs are running in that area.

Also, we have a strong well performance in Eagle Ford and the Barnett Shale Combo, which Tim will focus more on in some more detail. I think I read several reports today, and most of you all I think got it. Inside the most important point on the Highlight page is the fact that we had a significant discovery 60 miles away from EOG and El Paso's main drilling area with our really, our first Wolfcamp shale into what we call the Upper end Middle Wolfcamp section.

We had a peak 7-day average, flow rate of over 700 barrels a day equivalent a 24-hour rate of over 850 barrels of oil equivalent per day, both rates are flow line restricted. We calculate there would be somewhere over 1,200 barrels of oil equivalent per day in regard to --if it wasn't for the flow line restriction.

What's most important is that we have well over 200,000 PXD acres for this play. This play is going to end up being one of the major all-focused plays over the next several years that will allow us to grow significant double-digit rates for several years to come. We're only focused on the southern 200,000 acres. Primarily, you'll see later due to the fact that we have not been drilling vertical. The returns vertical, our margin, you don't have the deeper horizons, and the Spraberry gets thinner and thinner in this section. So we're really focused on about 200,000 acres to the south both in the next several quarters.

Vertical integration is still enhancing execution. It's saving us over $450 million per year. Essentially, our investments are already paid out. We'll talk more about it later.

Slide #4 in regard to our growth rates, we're targeting still 18% compounded growth rate for 2011 to '14. Again, as a reminder, this excludes anything from the deeper horizons in the Spraberry Trend area from the Strawn to the Atoka and also excludes the Horizontal Wolfcamp play. We expect full year production of about 125,000 barrels a day equivalent. As we mentioned last quarter, it's toward the lower end of our guidance of 125 to 130 for the reasons footnoted below that happened to us primarily in first quarter.

In addition, we have again, unplanned downtime during the third quarter in South Africa. In the asset, we lost about 1,000 barrels a day. And for different reasons, we're going to lose about 1,500 barrels a day in the fourth quarter. The South Africa, as I mentioned, is going to end up being less than 2% of our production next year and less than 1% in 2013.

What's happening is that the plant is reaching the minimum volumes of intake going to the GTL plant. We expect to have continued downtime over the next 18 months. Also, we have not mentioned this, but we collected $36 million for the third quarter in a take-or-pay from PetroSA. It covered production in 2009, 2010, it covered 3 periods of downtime during that period. As we continue, that was about 1 million BOEs. Because on the take-or-pay from an accounting convention, we have to put it in deferred revenue. We cannot count as production as we get paid for that downtime.

Over the next 18 months, including the fourth quarter, we'll continue to have probably down periods, and we expect to continue to have take-or-pay claims and collect it over the next several quarters.

Our production obviously up from 111 to 119 up to 128, and then a midpoint, up another 10,000 to 138. If you look at the midpoint, it puts U.S. production up 22% and then company-wide over the next 3 years, 18% CAGR.

What's also noted, we're starting to calculate our liquids percent increase. You notice in 2010, we were 44% liquids. We're already up to 52% liquids for third quarter, the acceleration of our 3 key liquids plays and then 60% liquids in 2014.

Going into more detail on the horizontal Wolfcamp discovery in our Giddings Estate well 60 miles away. It's really the first well in Upton County in the horizontal Wolfcamp shale play. As you can see, we put our horizontal primarily in the middle between the Upper Wolfcamp shale and the Middle Wolfcamp shale. Petrophysical and core analysis shows we have substantial oil in place in both of those areas. Again, I won't go over the rates again but unrestricted, we could have taken the well on up to about 1,200 barrels a day equivalent.

Microseismic shows that we successfully stimulated both intervals. But obviously, we're very excited about this discovery and this play moving forward.

Going into Slide #6 in regard to the map of where this is located. You can see EOG and El Paso continue to have -- with their announcements over the last 24 hours, continue to have very successful wells in both areas. The farthest area is about 60 miles away. And then also El Paso and EOG have had success about 30 miles away. That's the midpoint in Reagan County.

We're going to drill -- we're in the process of drilling one more well in Upton County. We're going to put 2 wells in Reagan County. As I mentioned, we're going to focus on 200,000 acres. We think it will be well above that over the next several years. That said, this is a tremendous potential for us. And a part of the area that we have not been focused vertically because the returns are more marginal.

As I said, we expect to drill 3 more wells. One is drilling now, 2 more after that. Then obviously, we expect to expand our horizontal drilling program in 2012, '13 and '14 over the next several years.

We started off with about 5,800-foot lateral. The second well will be closer to 6,000 feet. And then the third and fourth well, we'll be going out 7,000-foot plus.

And we think the optimum link will probably be in that 7,000-foot plus going forward.

Last Slide #7, Investment Highlights. Again, we got 3 tremendous growth areas. Over 20,000 drilling locations with over 200,000 acres minimum and growing. In the horizontal Wolfcamp play, we'll have well over 1,000 locations there. That's not in the 20,000 at this point in time. That play will allow us to continue to grow significantly over the next several years. We're forecasting 18% plus through 2014 and also production growth, operating cash flow of 30%, and as footnoted at $90 WTI and $5 gas. Again, we're saving more than $450 million a year with our vertical integration strategy and have done tremendous hedges in place both in 2012. And it's not mentioned in here, but you can look it in back, we have a 50% plus the same commodities both oil and gas hedged in 2013. Then obviously, we have a great balance sheet with debt-to-book of about 31%. Let me turn it over to Tim to go in more detail of our assets.

Timothy L. Dove

Thanks, Scott, and turning to Slide 8. Our third quarter operational results clearly show that these Spraberry Trend is a very large field that keeps on growing and keeps on giving, and will do so for many more years to come as Scott has alluded to.

As a sidenote, it's the play also that has the largest number of rigs running in the U.S. It has 11% of the total U.S. rig count. And as the largest acreage holder, driller and producer in this area, we'll continue to play a dominant role in the field.

We're seeing strong and very repeatable economics on our vertical program, which of course, has been the focus in the northern part of this play, the top 80% of the play as Scott has alluded to. Returns look very good, and most of the returns we're calculating still are based on the 140,000-barrel BOE type curve that goes when wells are deepened only to the Lower Wolfcamp. We believe, as I'll show in the subsequent slide, that as we deepen the wells to the Strawn, the Atoka and the Mississippian that our returns will be enhanced.

So turning to Slide 9 and with the topic in mind that is deeper drilling. This is an update of our activities and a review of the results of our vertical deepening program. As you can see in the top part of the slide, in the third quarter, we have some very substantially positive results. And we're getting more data day-to-day in terms of giving us confidence that the empirical data supports the deepening is really adding a lot of value.

For instance, in the Strawn, we've now drilled 113 wells into the Strawn. And for those wells for which we have 10 months of production, we believe it will be about 25% increase in cumulative production, which is obviously a substantial contributor in terms of economics.

Looking forward, we'll be completing about 25% of the wells that are in next year's program in the Strawn. In the Atoka and Mississippian, in the Atoka, of course, we have done 3-well program. One of which was a zonal test that is completing a well only in Atoka in the third quarter, and it tested 127 BOEs per day on a 24-hour test. So the objective there is to complete 2 or 3 wells more in this quarter. And then we have enough confidence now to say that our Atoka completions will occur in about 15% to 20% of next year's program.

Similarly in the Mississippian, we're seeing very good results in the second well. It was a zonal test again about 92 BOEs per day. And we have a couple more of wells drilled this year and have about more than 10% of next year's program slated to complete in the Mississippian.

As you look down at the bottom end of the table, it has to do really more with the economics and the EURs expected from each of these zones. Suffice it to say, we think a substantial resource potentially can be added especially in combination.

For instance if we are in a situation we have both Strawn and Atoka, we could increase EURs in the wells by some 110,000 BOE. So taking the well from 140,000 BOE to somewhere in the neighborhood of 250,000 BOE. We've done a little bit more work in terms of the cost assessments for the Atoka. What you see here is a tightened range of the cost and that's because of the more work we're doing. We believe we can go to water-based fracs. We are going to need 5.5-inch pipe on bottom. But that will also we believe allow us not to lay -- not to use a separate casing strength, an additional casing strength. And that's why we've tightened the ranges there.

In the Mississippian, we've actually increased this cost mostly again related to the need for 5.5-inch casing, and we are now increasing the number of stages pumped in terms of the completion in the Mississippian to 2 to 3 stages, each of which is adding cost. But nonetheless, each of these have a very strong economics. In the case of the Mississippian, probably in the neighborhood of $10 per BOE and very substantially lower even in the Strawn about $3 to $5 per BOE.

So essentially, what I'm saying is the deeper drilling is proving up and I think we're at a point where we can say it's going to become a big part of our vertical program going forward.

On Slide 10 is a recap of what's happening on our Spraberry waterflood. Of course, we had a flood in place since August last year. So after these 15 months or so, we now have pretty good confidence that the production wedge is building as shown on the graph. This waterflood is occurring only in one zone called the Upper Spraberry. That's 110 wells that we're talking about. So we can pretty much define now that we have a significant impact on production. And the key to this is that as we go forward, I think that wedge will continue to build.

And the result of that at least in this one area is we think we'll actually be adding reserves. We've already added reserves in the third quarter for this waterflood, and we'll also be adding more reserves by year end. The amount of reserves on this particular project, being only 7,000 acres, is not terribly meaningful just because of the limited number of wells. But the key is the process is working, we're seeing the effect and the next step, of course, is to scale up this activity into other areas.

We do have a larger 25,000-acre project that's been identified for 2012 and it's being looked at and evaluated as a part of the 2010 capital allocation process.

Turning to Slide 11. The proofs in the pudding in terms of reserves, I guess, you see that we have substantial growth in production up to 47,000 BOE, outstanding quarter. And we expect the fourth quarter to be outstanding as well.

We have eliminated essentially all of our oil trucking issues that we were dealing with in the second quarter and part of the third quarter. In fact, we added 11 trucks in the third quarter. We now have 26 crude oil trucks operating in the field, and we believe that's ample for our near-term needs.

In addition to which, one of our further objectives is to make sure we can get more oil on pipe. We have 5,700 barrels a day of new pipeline takeaway capacity that's coming in the first quarter of 2012. As a result of all this, we expect to be towards the high end of guidance for the year in this field.

Looking forward, we're still showing a very substantial growth rate. The production forecast that you see here have been in place for some time. But it's important to note and Scott alluded to this, but these forecasts do not include deepening below the Lower Wolfcamp, so they don't include any impact from Atoka, from Strawn or from Mississippian. And as mentioned earlier as well, it does not include what will be we think substantial impact from the horizontal Wolfcamp shale drilling campaign as it is expanded.

Turning to Eagle Ford at Slide 12. This is now -- it turns out also a very important area for the standpoint of rigs operating. It's the second highest rig count area in the United States with about 200 rigs running. And several operators in the play actually this particular quarter, have been discussing infrastructure limitations that have affected their operations. We actually had a first mover advantage. We feel like having been in the play so long and having our CGPs in place to a great extent. And with our trucking and pipeline contracts in place, we've had essentially no infrastructure-related issues during the quarter.

We are running 12 rigs and some of the data on those wells and rigs are shown in the box. Importantly, we are making strides in understanding the use of white sand as a proppant, about 30% of the program going forward will use white sand. And we're seeing very good results. When we compare white sand proppant wells to offset ceramic prop wells and that gives us confidence that this is the right thing to do going forward, where it applies.

One very important component of the results in Eagle Ford is the fact that oil prices for Eagle Ford condensate and crude oil have been improving. In fact, in certain of our areas, we're are now getting a premium over WTI of about $5 before gravity deductions. So in general, in our area nets to about $2 premium to WTI after gravity. That compares to numbers earlier in this year, they were somewhere in the neighborhood of $7 to $8 below WTI. So we had a substantial improvement. It has to do with increasing refinery demand for the lighter Eagle Ford production as it's attractive today in consideration of the fact that WTI is still $18 below the rent.

Turning to Slide 13. We got a lot of requests over several quarters for well performance data on the Eagle Ford Shale, and so we thought we'd share some of the third quarter results. These are third quarter wells, 24-hour flow tests.

As you can see, we're exhibiting very strong rates of production for condensate, crude oil, NGLs as well as natural gas. I'm not going to go through each one of these wells other than to say the average well in this table -- on these tables is 2,269 BOE per day. And what you're seeing is production has become more repeatable and predictable as we drill more wells up and down the trend.

Slide 14 then. Again, shows what the effect is of getting these wells drilled and put them on production, and we have substantial ramp up in the third quarter. We came in near the lower end of the range simply because as is the case always, the number of wells you put on production is the determinant of the amount of production you can announce. We have some wells in terms of their pop dates, slip until later in the quarter than we have planned. And those wells were put on production but didn't have as much of an effect on the quarter, but they have a substantial effect going into this quarter. And in fact, we're currently at about 20,000 BOE per day, up from the 14 average. And essentially what that reflects is we're catching up on the pop schedule.

And you see a substantial ramp up still in this field as we begin the process of acceleration, so this is going to be a substantial contributor to our growth going forward.

On Slide 15, this is similar well data for the Barnett Shale Combo Play. We have shown very strong rates. In fact, a lot of these wells are exceeding their type curve when it comes to their early production. We have substantial acreage position in this play that's growing slowly. We're trying to add more acreage of course. We have been increasing our lateral length to 6,500 feet or so.

But the important point is the average well here that's shown on the table is about 427 BOE per day. And in general like I said, in many cases, exceeding the early production type curve.

The effect we have shown on 16 then, we're showing increases in the Barnett Shale Combo Play production to about 4,000 barrels a day third quarter, up one again currently to about 5. So what you're really seeing is you look across these key areas in Texas. So all the areas, Spraberry, Eagle Ford Shale, Barnett Shale, they're all showing continuing strong production growth, which gives us a lot of confidence going forward.

And Slide 17, it recaps what I was mentioning earlier regarding the activity. We just happen to be in a position where we're in the 2 most active United States plays in both the Spraberry Trend area and the Eagle Ford plus a significant position in the Barnett Shale play, the #8 rig count play. I think the rigs here represents about 70% of the total rig count. And you can see as a result because of our position in these areas, we're very well poised to continue to execute and deliver strong operating results. And with that, I'm going to pass it over to Rich to discuss the third quarter financials and his outlook for the fourth quarter.

Richard P. Dealy

Thanks, Tim. And let's start on Slide 18. Net income attributable to common stockholders for the quarter was $351 million or $2.95 per diluted share. As Scott talked about, it did include $191 million after tax or $1.60 of unrealized mark-to-market derivative gains as a result of lower commodity prices at quarter end. Also, so as adjusted about $160 million or $1.35 per diluted share of adjusted earnings. That did include $26 million after-tax or $0.21 of derivative unwinds that we did during the quarter. So that one note that for you.

At the table below, shows third quarter guidance and our results, how we performed against those guidance. You'll see that we were within guidance and all the items or on the positive side except for current income taxes, which were slightly higher due to the incremental taxes that were recorded associated with the take-or-pay in South Africa that Scott discussed.

Turning to Slide 19, Price Realizations. You'll see that oil prices, at the top, they were down 11% during the quarter to $87.25. If you look at NGL and gas prices, they are relatively flat quarter-on-quarter.

Just a couple of notes on NGL prices. Most of our NGLs all end up in Mont Belvieu. We saw strong demand in Mont Belvieu for NGLs particularly given that the heavier part of the stream is more closely tied to LOS or Brent prices, and we didn't see the drop in those prices like we saw in WTI prices.

The bottom of the slide shows the impacts of our derivatives and VPPs on our reported prices as well as for your information.

Turning to Slide 20 and talk about production costs. Production costs for the quarter were up 5% to $13.47. Two main reasons for the increase. One in base LOE, we had -- saw increased labor rates during the quarter and some higher maintenance costs that we experienced during the quarter just on a routine basis. The second piece is our natural gas processing costs were up about $0.39 due to unplanned downtime at the Midkiff/Benedum plant in the Spraberry field, as well as we had takeaway limitations on NGLs there, so we we're rejecting ethane. But the impact was the downtime we had higher expenses and then two, with the takeaway limitations, we have less third-party revenue as a result of rejecting ethane. The plant gets from our percentage of proceeds-type contracts they have for products running to the plant.

Looking at Slide 21, fourth quarter guidance. Scott talked about 136,000 to 141,000 BOEs a day forecasted production for the fourth quarter. That does reflect the 1,500 BOEs downtime for October out of South Africa that's been already taken out of the guidance range. The rest of the items here in terms of guidance are consistent and very similar to what we had in the past quarters. So I'm not going to go through each one individually, but they're there for your review and modeling. And so with that, I want to stop there and we'll open up the call for questions?

Question-and-Answer Session

Operator

[Operator Instructions] We do have a number of questions in the queue. We'll take our first question from Dave Kistler with Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly with your commentary that the production growth doesn't have upside potential from Strawn, Atoka and Mississippian zones, as well as Horizontal Wolfcamp, if I just look at the numbers you're throwing out for tying in percentages of each of those areas into wells in 2012, is it fair for me to come to a conclusion that your production guidance could be muted by as much as 5%?

Scott D. Sheffield

Dave, this is Scott. Yes, I think a big swing factor, we've seen WTI in 2012 move from $78 to $92, $93 over the last 60 days. And I think a big swing factor even though we have some great hedges that protects it down that locks in $80 and $5.50 gas, we have a slide -- back on Slide 24, we have a lot of levers depending on what the price is. But depending if the price is strong, we have obviously, new job site potential with all the things that you mentioned. If the price is weaker, WTI, we got huge flexibility to keep our numbers similar to what we've been showing over the last 12 months as listed on Slide #24 in the appendix.

David W. Kistler - Simmons & Company International, Research Division

Okay. I appreciate that. And then thinking about Slide 24 for a second. One of the things that isn't mentioned in there is dropping down assets into the MLP and maybe a consideration of spending any of the service assets. Can you maybe comment on those as sources of capital for 2012 to fund any kind of CapEx above discretionary cash flow?

Scott D. Sheffield

Yes, in '12 and '13, we do have the -- I'm going to put them all into one category because we talked about noncore assets also. I'm going to put noncore assets including PSE units or drop downs all in the same category. So we always have that option in addition to that for '12 or '13 or '14.

Timothy L. Dove

I'll just comment Dave on the question of spinning out our services businesses, that's way premature. We're building fleets as we speak. We got more coming into next year in terms of pumping services. So any consideration of that is some time off.

David W. Kistler - Simmons & Company International, Research Division

Can you give us just a little bit of clarity on how much pressure pumping capacity from a horsepower perspective you have coming in maybe even just this quarter and then through 2012?

Timothy L. Dove

I think by the time we get done -- in the end of this year at 225,000 horsepower. We got about 50 coming in next year. That 275 will make us the 13th largest pumping services company in the United States-- or North America.

David W. Kistler - Simmons & Company International, Research Division

Okay. Great. One last one. I apologize. Looking at your rig mix. When you talk about 45 rigs potentially or have in the past in the Spraberry, can you just talk a little bit about how that might change given that the mix could move to some Horizontal Wolfcamp wells? Should we continue to target 45 or is that going to be very flexible?

Scott D. Sheffield

Yes, I think a combination on future results on the Wolfcamp shale play, adding -- most likely adding rigs there during periods in 2012. A big factor is what's going to happen to WTI. And so at this point in time, we still don't plan in going to 45. We plan on adding rigs but a big factor is what WTI. WTI, do you notice my last point on Slide 24, is slowing down the rig count acceleration, so we have that opportunity also in a couple of our key areas. But the bigger this Wolfcamp shale play gets, we anticipate adding rigs there. There is a possibility that we may slow down some of the vertical at some point in time.

Operator

And next we'll hear from Will Green with Stephens.

Will Green - Stephens Inc., Research Division

You mentioned that the horizontal Wolfcamp would be focused in kind of the southernmost 200,000 acres. I know it's early,you've only drilled 2 wells there. Do you have a good sense for how wide laterally those 2 wells are draining and enough to give us a sense for potential spacing there? Or is it just way too early to even get into that?

Scott D. Sheffield

Yes. First of all, we've only drilled one well. The other well, if you remember, we drilled one in the carbonate very far northwest. We had a very poor frac job. The second well was in the Lower Shale. I think people like Loredo and Apache are calling it Pin shale. It's the shale zone at the bottom of the Wolfcamp on top of the Strawn. Now with our second well. This is our third well. Our first well into the Upper Middle Wolfcamp. But we're expecting with over 200,000 acres, 140-acre spacing right now drilling 7,000-foot laterals that we could have over 1,000 locations. So 140 acres is the answer, right now.

Will Green - Stephens Inc., Research Division

Great. I appreciate the clarification there. And then I wonder if we could jump over to Eagle Ford. It seems like that versus a lot of the peers that are in the play your wells are really performing outstanding. And I guess just jumping my question, what kind of type curve are these wells following at this point if you had to look at it on an average basis? And do you guys anticipate putting out a type curve on that at some stage?

Timothy L. Dove

Yes, I think the fact is the areas we're doing the drilling in there are really some of the best areas in the overall complex of the Eagle Ford Shale. And a lot of people believe that the liquids-rich condensate area because the energy in the system with a significant amount of gas in the system will lead to higher EURs in this area, higher productivity, importantly. We're still using roughly a 6 Bcfe-type curve. The type curve is different in various areas. So that's one of our complexities as you go from the dry gas window in the south and east to the north and west, where you got all the way into the oil window. We have various different type curves. So there's no such thing as one type curve. But the fact is these wells are performing very well, as you said. And a lot of it is due to the fact that we have an excellent team of people working on this. We drilled enough wells right now where we have a technological advantage. We have the most technology in the play in terms of knowledge and all that's coming to bear. We're doing a good job in terms of drilling the wells and drilling it cheaply as well.

Will Green - Stephens Inc., Research Division

Great. And then just one more, just to hit on the cheaply as you mentioned. You talked about you're seeing similar results going from ceramics to sand. Is that on a EUR expectation basis or is that an economics basis? In other words, could we see you guys may be sacrifice a small amount of EUR for a significant amount of cost?

Timothy L. Dove

Yes, I don't think we're trying to sacrifice anything. What we're trying to do is get an understanding because the fact is we just started this process of using light sand this summer. So it will be way premature to determine the exact ultimate EUR effect on the ceramic well versus the white sand well. That said, early well performance is showing similar data for offset wells in other words ceramic versus white sand. And that's an indication at least in the short term that the well results would be very good and on that basis, very economic similar to the ceramic pump wells. But to answer your question it's going to be hard to know for some time until we really know the exact EUR deltas between offset wells.

Operator

Next up is Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Going back to that Slide 24, given the more one-off items in this year's capital program. Can you comment on how much spending you think you would need in 2012 to achieve just the 20% growth as opposed to the 20% plus?

Richard P. Dealy

Yes, we've looked at some numbers even down to 80, 85, Brian, in implementing some of these things that we can achieve 20% type growth rates.

Brian Singer - Goldman Sachs Group Inc., Research Division

I'm sorry. I guess the question is what level of CapEx budget would achieve that, with that -- would you be able to do that...

Richard P. Dealy

Spending cash flow basically at an $80, $85 number. It's going to be around -- cash flow is going to be around 17, in those numbers. $80, $85, we can spend 17, 18 and achieve the type of growth rates.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got you. And then when you think about developing out the Horizontal Wolfcamp and I guess it also depend on the commodity price environment, but do you see the incremental rig commitment and capital commitment as incremental to your program? Or would you think about backing off in other places?

Richard P. Dealy

I was asked already about the vertical Spraberry program. Obviously that will be an area that we could slow down the acceleration to 45 rigs. The returns looks like they're very, very similar. You get much higher production rates on the horizontal well per dollar invested versus a Spraberry deeper well. So a Spraberry deeper well, as Tim mentioned I think, is running up about $1.9 million all the way to the Atoka. And so those wells may come on 100 barrels, 120 barrels a day. And so these wells come on 1,000 barrels a day for about $7 million. So you can see, you get much more production by $1 invested in the horizontal play. So I see over the next 2 to 5 years, it will be a mix of those areas. And a big factor is if WTI comes back stronger as it has in last 2 weeks to $100 plus next year, you could do both.

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes, got it. And then lastly, the $7 million to $8 million well cost in Eagle Ford, does that reflect the benefits of vertical integration or are there kind of -- is there downside or I guess potential for inflation there next year?

Timothy L. Dove

Brian, that's essentially a blended well cost. So today, remember we've got one of our own fleets out there as well as a third party. By the end of this year, we'll have 2 out of the 3 that will be Pioneer-operated. So what you're seeing in those numbers is a blended number, of the 2.

Operator

And moving forward, we will hear from Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just in terms of the Wolfcamp, I think you mentioned that you guys are still out there buying acreage. Just wanted to get a sense of how much you think maybe you can kind of pickup in and around your existing position and then maybe kind of comment on an infrastructure there in that 200,000 acres.

Richard P. Dealy

Yes, we are -- we have bought land in September. We're continuing to look at adding additional land over the next several weeks and months. I think the big infrastructure, we don't at this point in time with our recent agreements of expanding Midkiff/Benedum with Atlas, and also NGL takeaway probably the next big item that we have to look at is the top of volumes we could seeing from this play. Right now, there's about 16 rigs running. Obviously, it can get a lot higher quickly over the next several months. So it's more about crude oil takeaway, adding more trucks and so we're addressing that now as we speak. There's also the line to the south that potentially could come in with Magellan and Longhorn that will be taking crude down to the Gulf Coast instead of going to Cushing. So those are some of the issues that we're looking at in addressing, and we'll have more answers over the next several quarters.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

And how about gas processing in that general area?

Richard P. Dealy

Well, I mentioned, our 2 of the largest plants in the area is Midkiff/Benedum. And those plants are just Northeast of our discovery getting to state, and we're in the process of expanding those plants significantly also. It looks like the gas-oil ratio and most of this in our areas is about 1:1,000. It's basically the gas-oil ratio, so we're going to end up having 90% liquids plus in a typical well as you get more into -- further into Southeast -- the gas-oil ratio does pick up more significantly. So we are expanding our plants. We are well down that road already and also NGL takeaway at our plants.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And could you guys kind of comment on any issues in terms of needing to drill, to hold leases in this area?

Richard P. Dealy

Yes, we have -- on our map, we have 75% of our production held by production of our 800,000 to 900,000 acres. That pretty much holds true in the entire area. We do have some leases that will expire over the next 2- or 3-year leases. And so we will have to protect those.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. So just to clarify, on the 200,000 acres to the south, you guys are roughly 75% complete there, is that right?

Richard P. Dealy

Just much the same ratio in the entire trend, 75:25.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. I guess just looking at your production guidance. You guys had a range for the fourth quarter of 136 to 141. Kind of looks like if some of the numbers that you gave when you kind of look at some of the individual areas that you guys are trending closer to 141 at this point. Is there a range, just a function of who knows what happens in the next 2 months included there could be some downtime, how should we kind of think about that?

Scott D. Sheffield

Yes, the biggest item we mentioned. South Africa, again, it was off the entire month of October. It's back on now. And as I sort of alluded to, we don't know when it's going to go off and on, and so we've built in the loss of 1,500 barrels a day. So the entire month was off. And so that was the biggest factor. So with the rates that Tim gave on current rates, if you put South Africa back on at about 4,000 barrels a day, you can see the numbers that you get. So that was really the big adjustment. So for South Africa off the month of October, the range would have been much higher than we've given you. But as you remember, we do have a history of take-or-pay and as things go down over the next several quarters, we expect to collect that but we can't come back and count that as production, deferred revenue.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And, I guess, with respect to your Spraberry waterflood, obviously, you guys are experiencing pretty good early performance here. What do you guys think potentially could be your incremental oil recovery? I'm sure you guys have some models that have kind of looked at that, just trying to get a sense of what that could be in the play.

Timothy L. Dove

In some areas, Leo, if you look to in the past history of these floods, in the zones that are flooded, you can actually get a substantial increase in EUR. Sometimes you see as much as a 50% bump in production. Also there may be a 25% to 30% increase in reserves.

Operator

And next we'll hear from Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

It looks like the Eagle Ford, you are restricting the wells. Is this just as a cleanup? Or are you restricting them kind of going forward?

Timothy L. Dove

They are restricted going forward. If you look back to the history of what's happened in the Haynesville or other plays, I think the data suggests pretty clearly that restricting the wells probably is the right thing to do for the long term. So we're bringing the wells on at lower choke settings, generally 12/64 or 14/64 to avoid damaging the reservoir. And we think we're seeing lower decline rates as well, which is the empirical data that suggests this is probably the right thing to do.

Brian M. Corales - Howard Weil Incorporated, Research Division

Is that an EUR increase? And if so, maybe, is it too early to quantify?

Timothy L. Dove

I think it is ultimately an EUR increase. It is too early to quantify though. With these wells having -- a lot of the wells having been on way less than a year. So you have to give us some time to sort of quantify what the effect would be. In the early stages, what you can say is we see a deduction in the decline rate which will tend to make you believe you have an EUR increase.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And you talked about the $7 million to $8 million blended cost. Is that using ceramic proppant?

Timothy L. Dove

Yes.

Brian M. Corales - Howard Weil Incorporated, Research Division

And what do you save by using white sand? Is that about $1.5 million?

Timothy L. Dove

$700,000.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then finally, can you maybe talk about cost? I know this is kind of the first Wolfcamp Horizontal in the southern area. I mean, are you all targeting a certain cost there? And is that going to vary within the 200,000 acres?

Richard P. Dealy

Yes, it will vary. We're targeting $6 million to $7 million. That's also net using PXD frac fleets. So -- and the reason the range is, it's much deeper. We're about 2,000 to 3,000 feet deeper on our Giddings area versus where 60 miles away where EOG is. We're going to see a range as you move South and Southeast on our acreage on that map. In Reagan County our AFE should be about the same as EOG. So that's a blended -- 6 to 7 is a blended rate.

Operator

And next we'll hear from Amir Arif with Stifel, Nicolaus.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

A couple of quick questions. First, the production numbers that you provided for 2012 by region in Spraberry and Eagle Ford, can you tell us how many rigs you're assuming for the '12 programs like in Spraberry you got 38 or are you assuming you'll do get to 45 to get that '12 number?

Scott D. Sheffield

Yes, all of those are the same rig rates that we put into in the last several quarters. Again, it's 45 and 14 on Eagle Ford and 4 on Barnett.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And did you say that you'll be able to achieve those with a CapEx as low as 17, 18 or is that assuming the 21 current levels?

Scott D. Sheffield

No, that's one of the items. That's 17, 18 with slow rig count acceleration. That's one of the 4 items that we list on Slide #24 as an option. So under much lower oil prices, we would probably take some of the rig count down.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

But you'd still be able to acheive the 20%?

Scott D. Sheffield

But still achieve 20% target growth rates.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And is that just by shifting to the more of the horizontals where you get the higher IPs per dollar spent?

Scott D. Sheffield

No, that's even before this recent discovery. That gives us another opportunity. We can probably get higher rates by cutting some of the verticals in Spraberry. That's not even built into that. We just made this. This well just came on the last 2 weeks. So obviously, it's a significant plus to that. But all my comments are referenced before that well came on.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay, and then...

Scott D. Sheffield

It had a very conservative number out there over the last several quarters.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And then I think I heard you mentioned that the 200,000 acres in the South that you're doing the horizontal drilling on. I thought you didn't have much vertical drilling but you said that .75 of that is still held by production. So it will be an economic decision. There's no need to drill that area a little more?

Scott D. Sheffield

No, a bunch of that acreage, we actually bought I think some acquisitions. We, historically, at our company over the last 20 years, have not drilled. We drilled very few wells in the southern. And we have a combination of University lands that has to be drilled on and a combination of acquisitions that we've made from 2 or 3 operators over the last 7 to 8 years and that's how we got a good base in that area. So it was drilled by other operators but historically, being there for 30 years plus,we have not drilled in those southern areas because of the poor vertical returns. So a lot of it is held by production for that reason. So we bought properties from people they have already drilled wells on it to hold it.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

I see. Okay. And then on the horizontals, on the additional horizontals you're going to be drilling later this year or next year, are you going to be targeting the same Wolfcamp zone or are you testing...

Scott D. Sheffield

At exactly the same interval.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Same interval. Okay. And then just a final question on the white sands in the Eagle Ford. You're seeing similar initial productivity out of the wells. Is there any issues over time with the -- does the sand hold up as good as ceramics or does it level off at a lower rate and any issues in terms that would make you decide which way to go.

Timothy L. Dove

What I would say is it's too early to answer that question. We need to see several years of data. The idea that you have a similar IP rate gives us some confidence that this could very well work. We're going to have to see how well the sand hold up versus ceramics in the longer term situation when the pressures come down in the well. We'll be able to let you know the answer when that occurs.

Operator

And next, we'll hear from Brian Lively with Tudor, Pickering.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just on the Wolfcamp acreage itself, it seems like right now, the popular buzzword is JVs. You guys are clearly ahead and set the pace with your Reliance JV that allows you guys to basically grow that asset within cash flow. Would you consider doing a JV on the Wolfcamp acreage?

Scott D. Sheffield

Not at this point in time. Our focus is obviously on proving up our acreage, understanding it more and see how big it could be. That's always an opportunity way down the road.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And is that just more of you need to delineate first or you just feel that it's more options around capitalization right now?

Scott D. Sheffield

We're excited about the play, the drilling. If you remember, we drilled 5 wells plus before we even thought about the JV. We do have a lot more acreage here that's held by production than we did at the Eagle Ford. So it's always an opportunity down the road as we did in Eagle Ford. But right now, we're just trying to get our wells down and evaluate the potential we'll probably have more acreage. So it's something waiting down the road. But right now, it's not the focus. There has been no to my knowledge, no JV in the Permian Basin to date.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just not yet, right?

Scott D. Sheffield

Yes.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Tim, I think this is a follow-up question just want to make sure I understood. I think you said that for 2012, you plan to drill like 15% to 20%, targeting the Atoka and 10% in Mississippian, I assume 25% or so is still for the Strawn. If that's right, my question is more, is that scalable up and down regardless of where you guys at or on total rig count? I mean, if you took rigs out of the Spraberry and drill more in Wolfcamp, would you still hold those percentages for your vertical program?

Timothy L. Dove

Well, I think what we're really saying is the Atoka and Strawn and Mississippian wells are going to have very strong economics and higher productivity than just drilling wells for the Lower Wolfcamp. And so I think if we were, for instance, as you said, reduce the rig count, I think we'd keep those wells in the program because there are going to be more prolific wells. So what you would be doing in essence is reducing the number of wells that are only drilled to the Upper Wolfcamp -- I mean, to the lower Wolfcamp, sorry.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

But those percentage actually goes up with the lower rig count?

Timothy L. Dove

Correct.

Operator

Next, we'll hear from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

In the waterflood area, Tim, you mentioned that you think that maybe the EURs will go by or the recoverable bond go by 30%. Is that of the original EUR or is it just a what's left?

Timothy L. Dove

That's the original EUR.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And when would you typically put a well in waterflood? Would you put it on immediately or do you have to wait to get to a certain point of depletion?

Timothy L. Dove

What we need to do in the case of this waterflood and in future ones is to properly drill up the area of where the waterflood is in place. And what I mean by that in this case is we drill this to 40-acre spacing. And this is the first waterflood it's ever been done by sub-40-acre spacing, the 7,000-acre flood we have in place now. As we look forward, it's plausible that a 20-acre space field might even do better in terms of recovery rates. And that's something we may want to consider. But the key to this is getting the wells drilled, having densely spaced wells and then in addition to that, add -- handle a few injector wells and/or convert a few producers that are existing into injectors. In that way, all you've done is drill up the field and you start reintroducing produced water. So it's an elegant way to increase production on the one hand, but also it allows us to dispose of produced water on the other, which is generally speaking, costly. So I think it has a lot of potential. And we think it's in the neighborhood of 40% to 45% of our acreage where this could apply.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And can you -- what sort of the rate of return on the incremental spending that you need to do to get that extra 30% out?

Timothy L. Dove

Well, let's see. It's the case that the cost of this is very small. If you look at the existing project, it's about a $6 million capital cost. As an example of that, I think we might be booking somewhere in the neighborhood of 200,000 barrels from this existing flood by the end of the year, and that's just this year as production bump. So -- and I think that's going to be increasing, so you can see the math on it, it's going to get exceedingly beneficial to us.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Are the operating costs -- are the incremental operating cost for the incremental barrels actually negative or are they still positive?

Timothy L. Dove

Well, they're slightly positive because you have to process the produced water and you have some electrical needs. We do not pump under high pressure but you have some positive costs. But they almost are entirely netted out by the savings on the disposal of water.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Great. Great. And if you look at 20,000 locations you have in the broad Spraberry, and you may have addressed this already. But if you drill 1,000 horizontal wells in that 200,000 acres, would you write-off any of it -- not write-off in the accounting sense, but just sort of would you reduce that well count of 20,000 by any?

Scott D. Sheffield

No, Gil. As I have mentioned, we have not drilled much in the South as mostly due to the acquisition. So we didn't have -- into returns vertically or marginal, it was not in our 20,000. Our 20,000 is a high grade. We probably got over 30,000 locations in the company. We high grade it to 20s and the 40s to get to the 20,000.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. So the 200,000 acres doesn't really have much of that 20,000 inventory?

Scott D. Sheffield

That's right.

Gil Yang - BofA Merrill Lynch, Research Division

All right. Okay. And in terms of Atoka cost range narrowed. I think, Tim, you mentioned sort of why. Can you just sort of highlight exactly why that potential incremental cost range changed?

Timothy L. Dove

Sure. In the last call, I think we have numbers in there that range from 250,000 to 750,000. The reason for that is we're just addressing the question of, did we have to use CO2 conveyed fracs or could we use cheaper water conveyed fracs? The next question was, were we in need of an additional intermediate strength casing or not depending upon the depths of the wells? And after further review and more analysis and having done the testing of 3 wells now, we've come to the conclusion that we can focus most of the program on water conveyed fracs. We can eliminate the additional string of casing by using 5.5-inch casing on the bottom as opposed to 4.5 inch. That of course has a cost associated with it. That's why they cost of what they are. In addition, we believe in most cases, we'll be pumping 2 stages instead of one in terms of the completions. And when you put your -- put the numbers together in relation to all of those, that's how you get this range, 300,000 to 350,000. That's now essentially a tightened range with more data.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, great. That's helpful. But do the 2 stages cost more than the 1 stage or is there?

Timothy L. Dove

Incrementally, yes, some cost on your second stage here. If nothing else, time and effort.

Operator

And next, we'll hear from John Freeman with Raymond James.

John Freeman - Raymond James & Associates, Inc., Research Division

Just following up on the deeper intervals again on the Spraberry. I'm just trying to make sure that I'm sort of thinking about this right. If you sort of add up all the percentages for 2012 on the various zones you're going to deepen to it's like 50%, 55% of your wells. But in your 2012 guidance, are you all embedding in some of that assumptions that you're going to do the Strawn and Atoka, or Strawn and Mississippian in the same wells?

Timothy L. Dove

Correct. Wherever we can do that, we will. But in some cases, where you'll be drilling Strawn-only wells. But the fact is that in a lot of cases, what you'd be doing is seeking out the opportunities to drill the wells through the Strawn and Atoka where that exists. And typically in the other case, Strawn and Mississippian where that exist. Those -- the Atoka and the Mississippian generally speaking do not overlap.

John Freeman - Raymond James & Associates, Inc., Research Division

Right. So is it probably too early then, Tim, to sort of have some rough idea of if you sort of just assume that in some cases you're doing Strawn and Atoka or in some cases, Strawn and Mississippian. What absolute percentage of wells are going to be deepened for the vertical program?

Timothy L. Dove

I can get that for you, John, because I know we already have the wells pinpointed, but I just don't have it on the top of my head. If you call back to Frank, and we'll get you that information.

John Freeman - Raymond James & Associates, Inc., Research Division

Okay. Great. And then just one other question, I know in Alaska, you've got a couple pretty important wells that are coming up. One of them is a deep test. I believe it was scheduled for this winter. Is there any update on the specific timing on that well and potentially when we might have results?

Scott D. Sheffield

Yes, John. Three months from January through March is when we'll be drilling the 2 wells. One will be frac-ed similar to what we do in the Eagle Ford, the horizontal Wolfcamp play and the Spraberry. And then the other one is the Ivishak well. The spud date will be in January. It would be finished by -- we have to be out of there probably by the end of March. And so I'm guessing at the earliest will be May earnings at that point in time.

Operator

And next, we'll hear from Sven Del Pozzo with HIS (sic)[IHS] Herold.

Sven Del Pozzo

Yes, IHS Herold. Just on Slide 6 again, horizontal Wolfcamp, just wondering if you have vertical well data to support the risking process that you used to call these 200,000 acres perspective.

Scott D. Sheffield

Yes, if you look at the bottom on Slide 5, petrophysical is logged data and we have core analysis in the entire 200,000 acres in that area. So -- and with the success of the wells by EOG, El Paso an approach raises our confidence level. So it's combination of logs, which is petrophysical data and core analysis.

Sven Del Pozzo

And do they go deep enough to actually give you a look at this deeper Wolfcamp that you're targeting?

Scott D. Sheffield

Yes, there's a lot of deep wells that have been drilled down into the Devonian going deeper and looking for exploration prospects in both of those counties.

Sven Del Pozzo

Okay. And then looking at the vertical wells drilled in -- a lot of vertical wells drilled in the '08 and '09, right, where your acreage is just like on your map that you show. So are you guys saying that that's the area that you think -- would that also with that arrow that you got on Slide 6, but we have the 60 miles there? So is it that whole area that you're thinking between those 2, the arrows, basically where you said 60 miles?

Scott D. Sheffield

No, our way is focused on Upton and Reagan Counties. That's 200,000 acres plus, so don't get focused on the 60 miles. Those 2 arrows. In other words, you don't have to be in that along those arrows to have good wells.

Sven Del Pozzo

All right. And how much does the vertical well data help you? I mean, do you use that data to map out these horizontal wells?

Scott D. Sheffield

Exactly. Yes.

Sven Del Pozzo

Okay. And where are your 20-acre pilots that you mentioned in the release?

Timothy L. Dove

That 20-acre pilot drilling is essentially up and down in different areas of the field. But normally, it's north of where you're talking about here Sven, it's in the northern counties and midland, Martin counties and so on.

Sven Del Pozzo

Okay and lastly when you say the Strawn, you feel it's about 40%. It's on about 40% of your acreage. I guess what causes you to exclude the other 60% and include the 40%?

Timothy L. Dove

The Strawn is not ubiquitous like the rest of the Spraberry plays, so it's not everywhere and not the whole 900,000 acres. Secondly, where it exists, there's a porosity cutoff that needs to be met before we complete in the Strawn, so it's a combination of those things that brings it down into the 40% range.

Operator

Next, we'll hear from Dan Morrison with Global Hunter.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

A couple of quick of questions. You said your micro size indicated you'd stimulated the full 800-foot thickness. Two things. How much sand are you pumping per stage? And then also what's the micro size say, how far out you're getting laterally?

Scott D. Sheffield

Yes, we did over -- we had 30 stages, over 200,000 barrels and over 6 million pounds of sand for those 30 stages. And the micro seismic showed that we effectively frac-ed up about 400 feet and down about 400 feet.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

How about laterally?

Scott D. Sheffield

Laterally, we went out 5,800 feet.

Timothy L. Dove

No, no, no. up to 1000 feet.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

No on the fracs?

Scott D. Sheffield

About 1,000 feet out.

Timothy L. Dove

Yes.

Daniel J. Morrison - Global Hunter Securities, LLC, Research Division

And if you could comment a little bit just of how you see the shale rolled out throughout the basin, does the lose potential as you get close to the shelf margins and then also it's hard to imagine that your a 854-barrel a day wells at the northern end of the -- it's got to extend -- you're not at the edge of the play?

Scott D. Sheffield

Most of our acreage in all these counties is in the deepest part and it's where the source rock is at the Wolfcamp. And the Wolfberry play became famous on the fringes. So obviously, they didn't have the source rock. Some source rock migrated up in this debris flows that people started drilling about 3, 4, 5 years ago on the flanks and that's why they coined it Wolfberry. You have better porosity and permeability. But they all came from these areas in Upton, Reagan, Midland and so on. That's really where the key source rock is, where these horizontal wells are being drilled.

Operator

Next, we'll move on to John Herrlin with Societe General.

John P. Herrlin - Societe Generale Cross Asset Research

You have 3 quick ones for me. With using sand, you're not worried about the anisotropic nature of sand like the sand breaking down versus ceramics for your fracs?

Timothy L. Dove

We haven't any concerns about that so far, John.

John P. Herrlin - Societe Generale Cross Asset Research

Okay, that's fine. With the Wolfcamp, are you targeting in the middle Wolfcamp shale intervals or silty intervals?

Scott D. Sheffield

Both. We've been using the -- we've been coining the term Tippett Shale, but that's where we're -- let's say marker. And that's where we're targeting our horizontals. We dropped it off these slides because nobody else was using that but it's a marker that we use so -- but we are targeting both.

Timothy L. Dove

And one thing, John, it's kind of laminated shales/silty-ish carbonate, a lot of different formations or a lot of different type of target zones but intermingled.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Great. Last one for me with the deeper Spraberry wells that you were talking about, any co-mingling issues from a production standpoint?

Timothy L. Dove

No, what we are doing is we are actively, as we've stated before, pursuing the acquisitions of some deep rights where it's necessary. We'll have about 75% of the deep rights where we need to be drilling deeper wells in hand by the end of the year.

Operator

And next, we'll hear from Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co., Research Division

But one kind of big picture question on the Spraberry. Scott, I mean, we have talked about oil in place number before. Could you maybe give an update in terms of after having gone to the Atoka and Mississippian, what would be the new guesstimate about the oil in place?

Scott D. Sheffield

In the last 2 years, excluding the deep and excluding the horizontal Wolfcamp, we were at 40 billion barrels of oil in place. The horizontal Wolfcamp play and the Atoka and the Strawn is going to increase that significantly. I'm going to have to wait until Chris and his team come up with some new numbers. It's going to go up substantially.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Okay. Maybe a quick math. 20,000 locations, let's just say, the 110,000 barrel EUR probably goes up to 150 by the time you're done averaging and combining. That gives me 3 billion barrels of kind of recoverable reserves, if I just do that math. And take a look at your '14 guidance of kind of production that you have take the midpoint of that. That still gives me 100 your RP off that pretty substantial growth from here. How can we think about maybe collapsing this RP ratio some more?

Scott D. Sheffield

Obviously, the top wells, we make hundreds of thousands barrels in wells that's going to shorten RP significantly and there's horizontal Wolfcamp play, that's obviously the best place to do it with substantial growth plays there. Before that, we were in the process of just continuing to ramp up over the years, even past 45, the thought was to continue to ramp up our rig counts over time on a vertical play. So those are really the 2 best ways to shorten your RP ratio in this field.

Rehan Rashid - FBR Capital Markets & Co., Research Division

Okay. So maybe I was headed towards revisiting the JV conversation, would that help take some money off of that table from along the curve?

Scott D. Sheffield

You may have missed it. But was asked that early on, at this point, we're not looking at it but, obviously, it's always an option down the road, so that's another option, too.

Operator

And next, we'll hear from Gabriel Subura [ph] with Caris & Company.

Unknown Analyst -

Most of my questions have been answered. Just on NGL pricing. Obviously, you've been benefited this quarter. Can you give any guidance going forward on where you see pricing? Are we still going to get an uplift there in Mont Belvieu?

Richard P. Dealy

Yes, I think we'll continue to see. I mean, a lot of it depends on supply-demand fundamentals. But based on what we're seeing out of the petrochemical industry, I would expect that we'll still see strong NGL pricing going forward.

Unknown Analyst -

Okay, great. And just back to the Eagle Ford, I appreciate the IP rates on the slide. Can you guys provide an EUR range for those 3 distinct areas you guys defined in the presentation?

Timothy L. Dove

Well, we talked about that today. The ranges varied considerably. In fact, you can look at some of the offset operators who are drilling oil wells into the west. And there you're seeing 300,000, 400,000-barrel EURs. And as you go into the dryer gas areas, you've seen wells that have -- that can make 7, 8, 9 Bcfe mostly dry gas. And between, you see a tendency of combination of those. That's why we give a blended number. It's incorporating all those data points.

Operator

And next, we'll hear from Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Just a follow-up on the Spraberry. So is the determinant for taking wells deeper, is it strictly the rock or do you factor in capital or are there other factors that determine whether you take these wells deeper?

Scott D. Sheffield

It starts off with our geological team in mapping. There's been several deep well drilled into the Atoka, in both Martin and Midland County. Those are the 2 key counties and where the deeper drilling is going on between the Mississippian, the Strawn and the Atoka. And those 2 counties. So everything has been mapped primarily based on deeper drilling and that's how we determine we're really -- and we're spreading our wells out in the Strawn. We have enough -- we drilled over 100 wells down the Strawn. So obviously, we got pretty good data now. We've only drilled 3 in the Atoka as Tim mentioned. We just kind of drill some more over the next 12, 18 months to determine how big it could be. But so far, we're 3 for 3 there, and the wells are coming on much better than expected. In the Mississippian, we just did our first well, but there's lot of offset data. Other operators have been going to it. So the next driver -- we're getting better returns. The focus, as Tim mentioned, is on the deeper drilling so we do get better returns there than we do just a straight Spraberry Wolfcamp into the bottom of the Lower Wolfcamp. So that we hope the deeper expands, the well cost did go up. It's getting up to about $1.9 million for those type of wells. And so -- but we're seeing much better and better results and as Tim mentioned, we put in that 5.5-inch casing. A lot of our wells are coming in 80 to 100 barrels a day and just staying flat. And we can't bump them off because we got 2 smaller casing. So we go to 5.5-inch casing. I would anticipate higher rates from these wells and more of a hyperbolic decline curve. Right now, some of these wells aren't even declining. We would camp up the wells off from these deeper wells, so...

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So just to clarify, so is there anywhere where you think you've got the Atoka with the Strawn or the Atoka and Mississippian, you're going to take it deeper just because of the economics. Okay. And then -- okay. And those percentages that you show on Slide 9, are those percentages -- the percentages of wells you're going to drill to those deeper formations in 2012? Are those -- is that the best guess of the percentage of acreage that you think is perspective? Because I know like, for example, the Strawn, I think in the past you said 25% to 50% of your acreage you think is perspective for the Strawn?

Scott D. Sheffield

The acreage is the better -- we're not -- it's a different percentage. And so we're not like the Atoka who's 25% to 50%, so we're not taking 50% of our wells down. So we need more data. So the Atoka has gone from just a few wells to a lot more. And so as we get more results in the Atoka, then you would see going into '13 most likely, there'll be a lot more wells and a higher percentage go to the Atoka.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Right, but say like in the Strawn, for example, so your slide indicates you're taking 25% of the wells down to the Strawn, whereas in the past, you said that you think 25% to 50% of your acreage has the Strawn. So what's the difference there?

Scott D. Sheffield

We said 40% of our acreage is perspective. But there is a percentage of our wells that we are not completing in the Strawn because there's no porosity, okay? So not every well we take to the Strawn. The Strawn is more structural. It's got to have porosity. The Atoka, we anticipate to be much higher success rate than the Strawn. So that's the difference. So we just need more data. It'll take us a good 2 to 3 years in each of these 3 intervals to determine. Eventually, you will see us most likely matchup more with the percent perspective acreage probably about 2 to 3 years from now in Slide #9.

Operator

And we'll take our final question from Dan Schniedwind with AMI Asset Management.

Unknown Analyst -

Quick question for you from a credit perspective. You guys are really starting to look like an investment grade company. Have you talked to any of the credit rating agencies about possibilities what you would have to do to achieve that? And I know they're usually asleep at the wheel on these things and the last to ever realize when you should be, but has there been any communication there?

Richard P. Dealy

Yes, we have constant communication with the rating agencies and have -- we agreed that I think we are heading to or an already at an investment-grade credit. So we're just waiting until we have more results there waiting on. So I think overtime, we expect to continue to head that way.

Operator

Thank you, and that is all the questions we have in the queue. At this time, I'd like to turn the conference back over to management for any additional or closing remarks.

Scott D. Sheffield

We appreciate everybody staying longer. Great questions and hopefully, you got the right answers. If not, you know where to get us here in the office. I look forward to seeing everybody on the road. Again, have a great fourth quarter coming up.

Operator

Thank you, and that does conclude today's conference. We thank you for your participation. You may now disconnect.

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