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Pioneer Natural Resource (NYSE:PXD)

Q3 2010 Earnings Call

October 27, 2010 10:00 am ET

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

Daniel Morrison - Global Hunter Securities, LLC

Michael Hall

Brian Singer - Goldman Sachs Group Inc.

Brian Corales - Howard Weil Incorporated

Ellen Hannan - Weeden & Co. Research

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

Curtis Trimble - MKM Partners LLC

Gil Yang - BofA Merrill Lynch

David Kistler - Simmons & Company

Michael Jacobs - Private Investor

Joseph Allman - JP Morgan Chase & Co

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Leo Mariani - RBC Capital Markets Corporation

John Nelson - State of Wisconsin Investment Board

Kenneth Carroll - Johnson Rice & Company, L.L.C.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Rehan Rashid - FBR Capital Markets & Co.

Operator

Good day, ladies and gentlemen, and welcome to 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, 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.pdx.com (sic) [www.pxd.com]. At the website, select Investors, then select Investor Presentation.

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 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.

At this time, for opening remarks and introductions, I would like to turn the call 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. Let me briefly review the agenda for today's call. Scott's going to be up first. He'll review the financial and operating highlights for the third quarter of 2010, another solid quarter for PXD. I'll then comment on the company's plans for the remainder of this year and talk a little bit about the future and where we go from here. After that, Scott's going to turn the call over to Tim, he'll update you on our drilling results and plans for the Spraberry, the Eagle Ford Shale and the Barnett Combo Play. Rich will then cover the third quarter financials in more detail and give you our 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 Sheffield

Thanks, Frank. Good morning. We appreciate everyone taking the time to listen to the call. On Slide #3 on the Highlights. As Frank said, we had another very strong quarter. We had adjusted income of $42 million or $0.35 per share. We were essentially met or under all of our guidance items, we put out three months ago. This does exclude net gain from a couple of unusual items of $7 million or $0.06 a share. But also excludes mark-to-market derivative gains of $63 million or $0.53 per share. We hit above our midpoint of guidance in regard to production of 114,600 barrels a day equivalent. We're up 1% from the second quarter. That's primarily driven by the production growth in the Spraberry with enough rigs now. We're starting to see Spraberry begin to shine like we saw in 2008. This is a quarter we'll talk a lot obviously about the Spraberry, the Strawberry and the Wolfberry.

In regard to our ramp up in the Spraberry, it's on schedule. Production growth is exceeding forecast, primarily driven by the Wolfcamp. And we'll start to see the strong starting to show up as we see over the next several quarters. We're running 25 rigs. We'll be at 30 rigs by year-end and expect to run 30 rigs during 2011.

The Eagle Ford Shale, I sort of look at it, it will have its heyday like the Spraberry this quarter to the next quarter with strong production rates going into the fourth quarter with all of our CGPs coming on and going into 2011. We're already up to seven rigs now in Eagle Ford Shale, continue to have more rigs as we go into 2011 and 2012.

In addition, we announced that we we're working with a large midstream company, we announced that over this week, in regard to enterprise, I will talk more about that in regard to processing transporting and fractionating our products coming out of the Eagle Ford area. In addition, all the seismic that we've been working on, we're doing our 3D seismic over the last 12 to 18 months since late 2008, it's turned out very, very successful as we drill three successful operating Wells in Tunisia with one well testing near 6,000 barrels a day.

In addition we've added very old attractive all derivative positions with the recent runoff in crude prices for 2012, 2013, primarily all oil with upside to $150 to $120. The worst on reports out this morning we heard and cost that we were doing knockouts, one thing we do not do is knockouts, and secondly, we are not selling calls on crude to prop up dry gas drillings. So those two things we do not do. These are continued three-way calls that we've been doing for the last two years.

Turning to Slide #4. Again, what's important based on our forecast on fourth quarter 2010, we're going to be hitting our target of 10% plus in regard to production growth, primarily driven by obviously by Eagle Ford in Spraberry. Our drilling capital stayed fairly consistent at about $960 million. We're forecasting 15% production growth. We see no problems compete [ph] in your production growth from all '11 to '13, we really see no problems hitting that, especially with the results that we're seeing out of the Spraberry, the Wolfcamp and the Strawn, they continued great Eagle Ford results, while it continue to spend within cash flow as we've done this year going to '11, '12, '13. Liquids production will continue to increase significantly as we get into 2013.

If we look at the little box in going into the fourth quarter, off the right-hand side of Slide #4, we expect obviously Spraberry to continue to growth and overperform. Eagle Ford obviously with on several wells coming on production in fourth quarter, they'll be up a couple thousand barrels a day. In Tunisia, with the recent results would be up at least 1,000 barrels a day, but most of the impact, you'll see will be in the first quarter 2011 from our three wells and also continued drilling -- appraisal drilling in Tunisia going throughout the rest of this year.

Slide #5, in regard to cash flow and capital spending, based on the current remaining strip, the last couple of months of the year, we still expect about $1.2 billion of cash flow. It does remind people does include our Deepwater Gulf of Mexico refund and excludes our upfront cash from our JV, which is primarily designated for midstream outlays over the next couple of years. The said drilling capital really hasn't changed in any of our key areas between Spraberry and Eagle Ford and Alaska, the primary drivers. Tim will give a little update on our Barnett Shale drilling and also Tunisia, a little bit more color on that. Lane capital state fairly consistent and midstream capital about $50 million and that will grow primarily designated to the Eagle Ford project now will grow going into 2011 and 2012.

Slide #6 in regard to operating cash flow, we still expect it to double about 2013 on a compounded annual growth rate of about 18% plus over the next three years.

And finally, on Investment Highlights on Slide #7 . Again, with an inventory of well over 20,000 drilling locations, I'm primarily focused on oil. Again, the Spraberry is what's shining this quarter. The Eagle Ford will be the shining star going into next quarter. Both of those are the key drivers for us over the next several years. Again, forecasting 15% compounded annual production growth rate with operating cash flow doubling by 2013, and we got strong price protection obviously with our three-way callers over the next several years.

Important continue to spend within cash flow we have done. We'll continue to lay on attractive positions. we're pretty much through '12. We'll start focusing on 2013, 2014 primarily on the oil side as we see crude run up in the next few months. We continue to extend our vertical integration project. That helps protect margins, especially in today's environment. And we're getting much stronger financially in regard to our financials. Let me now turn it over to Tim to go over our operations.

Timothy Dove

Thanks, Scott, and as we've been saying for some time our main focus is on operational execution. So focusing on Slide 8 then, the Permian Basin, Spraberry assets are beginning to show signs of significant over performance that is primarily the result of deepening the wells to the deeper Wolfcamp and the Strawn formations. And you can see its production is showing significant improvement, in fact 7% growth compared to the second quarter of 2010 on a quarter-to-quarter basis.

Of course, Permian Basin activity is very high. It's probably the most active oil drilling field in the lower 48 for about 172 rigs surrounding. And so ours is a significant component of that and that's where we're starting to see significant growth. And in fact, in the third quarter, our production exceeded the earlier forecast we have made in previous guidance by about 1,500 barrels a day. Importantly, the drilling program is on schedule, it's running all the numbers in terms of drilling 440 wells this year.

We also, as Scott has already mentioned, have rigs contracted to be ready to run 30 rigs beginning essentially at the end of the year. The important contributions in terms of the increments have come as I said earlier from the Wolfcamp deepenings, as well as deepening into the Strawn and contributions from the shaley silty [ph] integrals that were otherwise thought to be nontraditional pay. And we'll talk a little bit more about the impacts of that looking forward in a of couple slides.

We also have two horizontal wells we plan to drill. In fact, one of them is being almost done now. It's being drilled in the Upper to Middle Wolfcamp and conventional zone, and we're about 400 feet from having that well completed and expect to have the well TD tomorrow. It will be actually completed until December in terms of seeing production testing. In addition, there's another horizontal well plan in the Lower Wolfcamp unconventional zone. These are being drilled traditionally with about 4000-foot laterals and they're important for us to understand the potential application of horizontal drilling in these Wolfcamp zones.

We continue to do some drilling at least or our 20 acre campaign. We drilled about 15 wells this year so far on our 20 well campaign and have about the same amount next year. The idea is to continue to collect data for the 20 well campaigns looking forward as we pursue down spacing field wide. Importantly, returns are still very high. They're over 50% or so on a pretax basis in the field and well cost during the neighborhood of $1.2 million, $1.3 million about where they have been. We anticipate production continuing to grow in, fact faster than we had earlier predicted, and I'll talk on the next Slide.

The waterflood project is well underway. We begin injecting water a month or two ago. And as we said in earlier discussions on this topic, we expect production impact in the neighborhood of six to nine months after the injection of water so that's anticipated during the first half of next year.

Turning to Slide 9. We are beginning to see the impact of deepening the wells as compared to the old type curves. So what you see in the slide on the light green is our traditional 110,000 BOE tight curve and we're depicting above that line is the 2010 well performance where we have several wells down of course that have been on production as much as five months or more. And you're seeing a dramatic increase in terms of the contribution of the Lower Wolfcamp where it applies, which is in every single well and the Strawn where its perspective which we're saying is in 30% to 40% in the field areas. And what you can see is about a 30% increase in cumulative production during that five-month period.

So what we're doing here is we're beginning to establish an empirical data set that suggests we're seeing significant production response from the deepening of the wells. And the next step of course will be to adjust our tight curve upward when we have a few more months of data anticipate that happening early 2011.

Slide 10 is a slide to discuss our vertical integration. And of course, in our case vertical integration has been put in place in the Permian Basin elsewhere with the objective of mitigating cost creep and minimizing execution risk. Toward that end, we have two of our own frac fleets operating in the Spraberry Trend Area and we have two additional fleets coming, one in the first quarter and one in the second quarter. And we're also in position to have all of our sand supply for these fracs in place to 2015.

Our tubulars are in place through the end of 2012 and our pumping units are in place in 2011 although sooner, we'll be extending that contract into 2012. We have about 12 of our own rigs and we have those operational in early 2011. That will make us about 40% self-sufficient when it comes to drilling for 2011. And it's suffice it to say, we're taking these steps across the board in terms of acquiring these facilities and equipment in order to make sure that we can get the jobs done for minimized execution risks because Spraberry Trend Area production will be so critical to the company going forward. And notwithstanding execution, we expect that we will be able to drill the wells with our own internal services, some $200,000 to $300,000 less than if we simply were to use all third-party services.

And that's a substantial increase in returns that will be associated with putting our own equipment to work. I think given area of our field operations will be in the neighborhood of 30% to 60% self-sufficient looking forward to 2012. The higher number being in those areas, we feel like the markets are tight and we'll be saving to more cost street. That will be where we put more equipment to work.

Slide 11 then is the sort of the manufacturing oil growth slide. In which we depict looking forward what sort of anticipated production growth we expect. As I mentioned earlier in the third quarter, we significantly exceeded the earlier forecast by about 1,500 barrels a day. That's led us to increase our fourth quarter estimate from what had been 34,000 barrels a day now to 36. You'll see if you compare these curves with what we had in prior earnings calls, we have not yet changed the outlook for 2011 to 2013. I would anticipate we'll change these estimates when we put in place the new type curve I've mentioned that reflects the deeper drilling and the accessing of the deepest Wolfcamp and the Strawn in all the new drilling campaign. We already showed about a 25% production figure looking forward and anticipate that will increase as we change our type curve.

Now changing to Eagle Ford, that's on Slide 12. We were right in the middle of a significant ramp-up and that's continuing right on target in terms of the drilling and the completions and the implementation of our midstream build out. We currently have six wells producing. One of those new wells were just tide into one of our new central gas processing facilities on October 1, and we'll have other, in that same facility tied in shortly. We have eight wells that are about completed and awaiting on CGPs just to give you a feel for this, our first one, as I said came on October 1 and the four additional ones that will be coming on serially between now and mid-January. But that will then allow us to tie in all these wells that are waiting and we have seven rigs running, as Scott had mentioned that it leaves us with about eight wells awaiting completion. So we're building a large inventory of producible wells such that when we get this infrastructure in place, we'll see a dramatic ramp-up in production.

Similar to Permian, we are taking steps to protect ourselves both with regard to execution and costs brief in connection with third-party frac fleets and our own frac fleet, we've contracted the third-party fleet to work only for Pioneer for two years beginning first quarter and we have our own frac fleet coming second quarter 2011. This will allow us to be largely self-sufficient in 2011 frac-ing and completion of wells, which is an extremely tight area of the business of course today as the Eagle Ford Shale rig count continues now to exceed 100 rigs. We also, as Scott had mentioned, we're pleased to have announced earlier this week with enterprise the agreement for processing fractionation and transportation. That will amount to about a half of our liquid-rich gas and 100% of our common safe production.

And then Slide 13, a little bit more on well results. Actually well results continue to be very strong and consistent with what we see in the past. And we've seen this up and down our acreage. We tend to get very consistent with our results, which is a very good thing. Our focus of drilling continues to be in the liquid-rich gas area, cannon side area and so far, we've tested eight additional wells with an average of about 2,000 BOE per day each. These are on restricted flow test, so we're following these wells up to be relatively low choke sizes, and so you'd see these numbers that'd be slightly less than earlier numbers when we're using larger chokes.

But nonetheless, from an internal standpoint we look at these tests being very, very consistent with the prior wells and gives us a lot of confidence to the consistency and also the productivity of these wells, and we'll see that more and more as we start tying these wells into production when we get to midstream facilities put in place.

And in 14, it shows the ramp up we expect. We're really right on target. One of our objectives of course, was to hit the year-end exit rate of about 5,000 BOE per day. That's still off target and those numbers all remain intact. What you see in this slide is still our base drilling campaign, that shows the number of wells to be drilled at the bottom of the slide without any acceleration of drilling. I think it's likely that we will accelerate drilling above the number of wells shown, but that will be announced only after we have our 2011 capital budget put in place. But suffice it to say the amount of drilling shown below is that which will preserve our leasehold going forward in the Eagle Ford Shale. As drilling accelerates and the midstream builds out, you can see the dramatic increase in production ramp as shown over the next several years. So we're right at the inflection point where Eagle Ford is going to start taking off. We've got an excellent team of people working on this project and we have a lot of confidence this is going to be outstanding project for Pioneer and our partners.

At Slide 15, is on the Barnett Shale Combo Play. We think this could be our third leg of Texas-based liquid rigs drilling combining that with the Eagle Ford Shale project and our Spraberry Trend Area. We have over 48,000 acres that were leased, that would yield about 500 drilling locations and the first well of which is being drilled as we speak, we're drilling about 3,500-foot lateral and we'll be getting back to you with results that probably won't be on production until the latter part of this year. But suffice it to say, we're excited to see how the results from this well works out, as well as a series of additional wells we'll be drilling between now and the year-end in the combo play.

Finally, the last that I'm going to cover is on Tunisia. That's Slide 16. As we had promised earlier this year, we wanted to report in a separate release the results from the three-well campaign, extremely successful campaign, I might add. We drilled two wells in the Cherouq concession. That's showing on the orange on the map, and one in the Anaguid. Anaguid permit which is shown in the blue on the map. The importance of this is significant in the sense that the Anaguid well was the first successful story in well that far to the Northeast. In fact that's the same formation we produced in quantity in the Cherouq and Adam concessions. So this is an important step out well, if you will, and opens up a lot of prospectivity as we look to the Northeast part of our acreage.

The three wells importantly tested at a combined production rate of about 10,000 BOE per day. We owe a lot to our geo-science team for improving our seismic reprocessing to be able to really identify these targets. And we have two additional wells. We're actually in the -- one of which is in the process of drilling and one to be drilled a little bit later in the fourth quarter to advance our knowledge of this seismic reprocessing and increment production, which we expect now to increase from about 5,000 barrels a day where it sits today and then somewhere in the neighborhood of 8,000 to 9,000 expected in the first quarter next year.

And as I said in relation specifically to Anaguid, this has added significant resource potential as we look to the Northeast in our acreage. Where we have a total acreage position of about 3 million acres. So it's really opened up some new horizons for us. We don't have a slide on a couple of areas, but I want to comment about Alaska in the sense that we're continuing to drill there, we've had a very strong results from our first dual lateral well, which tested over 1,900 barrels a day. So this is a lot of confidence to Alaska. It continues to show good results and provides oil-based running room for us. Even though we're not doing much drilling in some of the other areas, for instance in our Mid-Continent areas and in Raton and in related to the Edwards trend area, we're maintaining production on those areas essentially flat due to the outstanding efforts of all of our personal in those areas, and even though we're not doing much spending in these areas, these areas are contributing substantial cash flow. In fact these three areas contributed over $100 million of operational cash flow in the third quarter.

Now I'll pass to Rich, for his review of the third quarter financials and his outlook for the fourth quarter.

Richard Dealy

Thanks, Tim. I'm going to start on Page 17. As Scott mentioned, net income for the quarter was $112 million or $0.94 per diluted share. If you adjust that mark-to-market derivative gains, there were non-cash for the quarter of $63 million after-tax or $0.53 per diluted share that would equate to $0.41 per diluted share of adjusted earnings. In addition, as laid on the slide here, we had about $7 million or $0.06 for the share of credits that hit the quarter on net basis that were unusual items. So adjusting for those items we would have been at $0.35 per diluted share.

At the bottom part of the Slide, you'll see we compare our guidance coming into the quarter with our results, and as you go down the list, if you exclude the unusual item, we're generally at the midpoint or the positive side of guidance on all each of those items.

Turning to Slide 18, in price realization. This is a little bit different slide than what we've shown in the past. What we've done in the bar charts above is showed our realized prices. These exclude VPP impacts and derivative impacts, and so you can see that oil prices were down 3% from the second quarter, NGL price were relatively flat quarter-on-quarter and gas prices were up about 5% relative to the second quarter.

At the bottom of the slide, we lay out on either a per barrel basis or a per Mcf basis with the VPP impacted our price and then the impact of derivatives to it. But I think that the highlight here is you can continue to see the benefit of our derivative position over the last quarters, making a big benefit to our positive impact to our price realizations.

Turning to Slide 19, we'll talk briefly about production costs, production costs for the quarter were up $1.15 per BOE. As we talked about in the second quarter, the biggest driver was that we had production tax credits or refunds that we received in the some in the first quarter, some in the second quarter, so those were a little bit artificially low so that was part of the increase and then the other item was we had a higher work over activity during the quarter, primarily in the Spraberry area and in Alaska. I mean the positive news is that our base LOE production costs continue to be consistent quarter-on-quarter and the asset teams continue to a great job of managing their cost structure.

Turning to Slide 20, and nearly focusing now on fourth quarter guidance. Fourth quarter production is expected to be $115,000 to 120,000 BOEs per day, still reflecting a 10% growth over the fourth quarter of 2009. Production costs similar to the second quarter of $11.75 to $13.75 per BOE. Exploration abandonment of $35 million to $45 million, really reflecting lower risk drilling that we have going on in Eagle Ford, Tunisia and Barnett Shale that Tim talked about, but in addition, we have one well that's targeting an oil prospect in Utah that was a commitment well that we entered into agreement a few years ago and we're now drilling in the fourth quarter.

The other items on the page are very consistent with where we were, if not exactly the same with the second quarter and in respects the first quarter. Some we'll go to those in detail but there for your information as you look forward to forecasting our fourth quarter results. So with that, let me stop there, and we'll open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll hear first from Dave Kistler with Simmons and Company.

David Kistler - Simmons & Company

Real quickly in the Eagle Ford with the midstream buildout that's taking place there, what kind of running room will that give you going forward, especially in light of the comments that you might accelerate drilling there as you put all four new systems in place, will that provide sufficient running room for the next year or two? Or how should we think about that?

Timothy Dove

Yes, Dave, this is Tim. First of all, the way we build the CGPs is in a modular fashion such that we can actually build out the systems to larger capacity with a lot of significant amount of work. But that said, the initial CGP build out, this will range between typical $50 million, $70 million a day of capacity, but with the ability to expand. So it certainly will handle first couple years of drilling at a minimum, at some point in the future, we'll have results that exceeds the expected numbers. We can expand those CGPs. So I think it's an expandable modular process we're looking at. So we have no problem handling even in incremental production from acceleration.

David Kistler - Simmons & Company

And then as you guys start to do more vertical integration within the Eagle Ford specifically, can you talk a little bit about what your expectations are for well costs, maybe where they are today and where you kind of think they'll be over the next year or so?

Timothy Dove

I think first of all, vertical integration for us is going to do some good things with regard to what essentially has been the biggest creek factor, which is completion costs. We're seeing really dramatic increase in completion as you know, Dave, somewhere in the negative [indiscernible] depends on how you calculate it during which timeframe 50% to 100% increases. And some of the service are trying to generate additional increases as we speak even for the fourth quarter of additional 15% to 20%. So it's such a tight market, it's such a tight service that numbers are getting outrageous. To give you a primary reference, we think we can complete the wells for $1 million less than our competitors. And so I think that's where you're going to see the benefits from vertical integration really coming home to Pioneer. We've got to make a decision really for 2012, do we have other frac fleet to address what will be an expanding amount of drilling. So suffice it to say we think this vertical integration as a very fast payout in today's world, we have a very frothy public-services market.

David Kistler - Simmons & Company

Just for clarification, current well costs are running [indiscernible] eight?

Timothy Dove

Great job, in fact, I didn't mention this, but I should've earlier, we've done a great job on reducing the number of days drilling. We're down about 20% since we started drilling. In fact, we drilled just the other day our fastest spud of TD [ph] well about 18 days. That's a dramatic increase of how the drilling team has done and that's dropped well cost down to about $7 million to $8 million. What we're really seeing is we're quickly seeing efficiencies that will really thought will come later in the life of the project.

David Kistler - Simmons & Company

One last question, just switching over to Tunisia. As you guys continue your drilling program there, do you know kind of the number of wells you're targeting where you'll make a decision on whether this is something you want to develop or whether this is something that is core or may not be core to Pioneer and might be a source of funds at some point?

Richard Dealy

Yes, Dave. It looks like the current rig activity we're going to drill a couple more wells by year-end and then our capital budget will be coming out late this year, early first quarter and we'll be making some decisions for 2011 at that point in time.

Operator

Our next question comes from Brian Lively with Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

Tim, you're discussing the Eagle Ford volumes, but just wanted to clarify what is the current capacity in the Eagle Ford for a year ago and you volumes from the wellhead to the barrel's point and then as you add these four plants, where will that capacity go to?

Timothy Dove

I think the average CGP is probably putting in today's about 50 million cubic feet a day equivalent plant. So I'd rather site it more towards January. We have about a capacity for 200 million to 250 million cubic feet a day.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

That's equivalent [ph]?

Timothy Dove

Yes. That's the equivalent.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

And then in the Spraberry. I think in the release you have said something like 50% rate of returns with the 22 program. What's the EUR assumption behind that return number?

Scott Sheffield

Can you repeat the question one more time? You cut out there.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

The Spraberry 50% rate of returns for the 2010 program, what's the EUR assumption?

Timothy Dove

That's the base type curve 110,000 barrel case BOE.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

And then how many strong wells have you actually co-mingled to this year?

Timothy Dove

I'm going to say it's in the neighborhood of 25 to 30 wells in that neighborhood.

Brian Lively - Tudor, Pickering & Co. Securities, Inc.

Back to the Eagle Ford, have you changed your type curve assumptions on the Eagle Ford considering where the wells are coming in? It looks they're as good if not better than what your other tight curves were adjusting.

Timothy Dove

Well we're not yet in a position, we'd say we're ready to do that. We're obviously looking at these levels and needed to get them on longer-term production. Those are production tests you're looking at.

Operator

Our next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

First, on the horizontal program in the Spraberry that your wells -- that you're testing, can you give us a little bit more color on what the plans would be beyond the two wells if those wells are successful and how applicable those horizontal opportunity is to other parts of the Spraberry to the Wolfcamp position?

Scott Sheffield

Yes, Brian. As Tim said, one is going conventional which in the middle Wolfcamp, and one is going to be lower into the resource unconventional. So obviously, if either one of those are successful, we'll probably put in more drilling, horizontal drilling in budget for 2011. We get asked a lot about how it would long-term impact our plan whether or not we most likely if one of those were successful or both will continue to drill vertical, but at the same time develop some horizontal in the Wolfcamp or combination of both. But right now, we need to wait to get good results from the two wells, which will be first quarter of next year.

Brian Singer - Goldman Sachs Group Inc.

And then when we think about the gas coming as a result of the Eagle Ford with some of the additional associated gas coming out of the Spraberry in the Permian, how should we think about the trajectory of your gas production over the next four, five quarters?

Timothy Dove

Our gas production in the Permian Basin amounts to probably about 20% of the total BOE, so you simply can take the estimated BOE cap as shown on the graphs and take about 20% of that gas. Eagle Ford depends on which well we're speaking of, which exact are, but the gas content usually runs between 40% to 50% of the stream. So I think you can do the math, just simply take our two curves and use that kind of a percentage.

Ellen Hannan - Weeden & Co. Research

And do you expect the rest of the portfolio then decline and Raton the shale lot plan et cetera?

Timothy Dove

What I think about Raton, I'd say Raton and Mid-Continent assets are on a mid-single digit decline rate and that's where a lot of great work on our staff to keep it at that. But that's essentially no spending.

Operator

Our next question comes from John Nelson with Macquarie Capital.

John Nelson - State of Wisconsin Investment Board

I just noticed that your Spraberry wells were flat sequentially, despite I think a pickup in the rig count. I was just wondering if there was any delay sort of due to rain or service tightness or was that the plan number of wells for the quarter?

Timothy Dove

Yes, we're right on target. We have 306 wells already drilled through September, of course, we'll be increasing the rig count through the year so it's back lated in terms of total wells, but we are right on the number to hit basically 435 to 440 wells for this year.

John Nelson - State of Wisconsin Investment Board

And then just around the 30% to 40% commentary for Wolfcamp prospectivity across your acreage, are some of those specific activities sort of in the South and Crockett in the area county, do you think that will open up the same new areas for you guys or do you think that 30% to 40% is still where you guys are at?

Timothy Dove

I want to clarify, we were seeing that in terms of the deepest Wolfcamp, it is ubiquitous essentially across our acreage. We think it's basically 100% of our acreage is prospected for the deepest Wolfcamp. The Strawn, we would say 30% to 40% of the acreage so let me clarify that first. The strong potential is seen to be really in the central part of our acreage. That's where -- it's the strongest potential. So what we believe where we've drilled wells to the South are area of the deepest Wolfcamp is best and the lower and southern perimeters of our acreage.

Operator

Our next question comes from Brian Corales with Howard Weil.

Brian Corales - Howard Weil Incorporated

Going back to the Eagle Ford. I guess, with the decreased drilling time, even if you kept seven rigs flat, it probably can still drill, I guess more than 70 wells next year. Is that a fair assumption there?

Timothy Dove

Yes, the fact is we're doing a very good job of increasing efficiencies. And so I think we will probably drill more than 70 wells. We haven't yet come out with the exact number yet.

Brian Corales - Howard Weil Incorporated

So we'll probably get that next order with the budget or we can better quantify?

Timothy Dove

That'll be associated with the 2011 capital budget release.

Brian Corales - Howard Weil Incorporated

And then switching to the Spraberry. I think you mentioned $1.2 million or $1.3 million cost, is that the deeper going to the lower Wolfcamp and the Strawn?

Timothy Dove

That's correct.

Brian Corales - Howard Weil Incorporated

And that's up from -- and if we just go into the Upper Wolfcamp, that would be about $1 million to $1.1 million?

Timothy Dove

That's why. That'd be about $1.1 million -- I think earlier this year, we're talking about $1.05 million drilling cost at really about $1.05 million to $1.1 million, it's now $1.2 million to $1.3 million depending about how far you deep in the well.

Brian Corales - Howard Weil Incorporated

And then finally, I know you all talked in the past on Tunisia in terms of you have to drill a couple these exploration wells, you look to see whether it's monetize or if this is -- what's kind of the next step for the company? Is this something that you think it gets monetize over the next 12 to 18 months or is it still there's a few other exploration targets past these next two that you're all looking at?

Scott Sheffield

Yes, Brian. As I said earlier, we're continuing appraisal drilling until the end of the year. Tunisia will be looking at the CapEx next year. There's been some positive order vision results by some other operators. There's a hot shale zone that we just court recently. That's very positive, so we're taking a look at all of our Tunisia in various plays and we'll make a decision early next year regarding the CapEx.

Brian Corales - Howard Weil Incorporated

And how are most a lot of these exploration, the targets that maybe Tunisia or areas around it, how are those being valued in the M&A markets? I mean is it -- is there a lot of value to this potential shale or is this something that I mean, or is that something that Pioneer will maybe willing to keep a hold onto?

Scott Sheffield

Yes, we do know at this time. We have not received the court announced it back. There's been some other work done by Eni and ETAP which has been very, very positive. And so it could be -- there's going to be zones as well as we're seeing like the Eagle Ford and other zones in the U.S. I mean there's going to be zones like that all over the world and North Africa just happens to be one of the best spots to go into the source rock. So obviously, it's going to be a focused area as long as you can move the product and obviously to the European markets. So it's something that's very, very positive.

Operator

Our next question comes from Spendo Polto [ph] With IHS.

Unidentified Analyst

You got any thoughts on dropping any assets in the PSC?

Scott Sheffield

Yes, we will continue -- obviously, from a standpoint of a PXD meeting additional capital, we don't need to do it. The valuation of the PSC is still strong. So we talked about doing that every couple years. So obviously, '11, '12 it's still a possibility. So we'll continue to evaluate it. But right now, PSC is doing well. It's drilling with two rigs and moving forward with its growth.

Unidentified Analyst

Per acre in the Barnett Combo Play, what's the rough dollars per acre you've invested to assemble that position?

Scott Sheffield

Yes, it started 300 to 500 an acre. It's been a tie recently as 750 to 1,000. It's going to average somewhere in between those numbers. Our position close to 50,000 acres.

Unidentified Analyst

Your cost savings, you talked about per well in the Spraberry of $0.2 million to $0.3 million. Would that come on to -- so basically, you'd go back down to $1 million, if you're at $1.3 million now with the deepening, you'd back out the $0.2 million to $0.3 million?

Timothy Dove

I think that's reflect to the fact we anticipate that the actual numbers for 2011 drilling are going to go up for those that don't have their own completion ability. We're seeing dramatic increases in what's being requested for our pumping services. For instance, we can complete our own wells for about $200,000. Third-party -- I'd say price request are now hedging up to $400,000 to $500,000. So that's where the $200,000 to $300,000 savings will be predominant and that is in pumping our own wells.

Unidentified Analyst

Regarding again the lower Wolfcamp development, you said the best stuff is on the southern perimeter of your acreage. I'm wondering what makes it the best?

Timothy Dove

Well, I meant to say if I didn't make my self clear is the lower Wolfcamp is a ubiquitously perspective across our acreage. What I'm saying is we don't think it sounds there were acreage, we're not as positive about it. I guess that's what I'm saying to.

Unidentified Analyst

So I misunderstood. So the southern perimeter is not the best part of your Wolfcamp?

Timothy Dove

What I mean to say is, let me clarify this, ubiquitously, the lower Wolfcamp shale is a perspective across our acreage. We think that the southern extend of our acreage, we're start to feel like but the quality of the Wolfcamp starts to decrease.

Unidentified Analyst

Is that the thinner parts of the lower Wolfcamp that you're most interested in trying horizontally? I'm wondering about the trade-offs between doing the vertical well into the lower Wolfcamp and versus horizontal development? I was kind of wondering about the thickness and how it changes across your acreage.

Scott Sheffield

Yes, we're targeting where it's thicker of 200 to 300 feet zones in the lower Wolfcamp resource. And that's more in the middle to the upper middle to the north of our acreage is where it's thicker, more consistent to lower. As Tim said, it's thinner. We got well rights of anywhere from 15 barrels a day to 50, 60 barrels a day in the lower Wolfcamp by just completing several wells by themselves. And so we've already gone back and looked at the course from the University of Texas, wells is drilled back in the fifties and sixties. We've taken recent course ourselves. So the TOC is very, very high. And so the next step to see if we can get the results in regard to drilling up 4,000, 5,000-foot horizontal. So we just got to try it before we give up and just do the vertical completions.

Unidentified Analyst

Just an accounting question, in your cash flow from investing activities, there is underneath additions to PPT, you got additions to other PPT, and I was wondering what are the types of investments that are captured by that line item?

Richard Dealy

It would be basically our frac fleets, as Tim talked it's also going to be our drilling rigs that we've acquired during the year. So those are the main two items.

Unidentified Analyst

And midstream as well?

Richard Dealy

Midstream will be in there too. That's correct. There'll be investments probably $15 million to $20 million thus far this year.

Operator

Our next question comes from Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets Corporation

Quick question on Tunisia here, I guess you talked about your production ramping up to 8,000 to 9,000 BOE per day. Is the majority of that increment going to be oil or is there any gas component there as well?

Scott Sheffield

In Cherouq, we are selling 100% oil and also in Anaguid, we'll be selling 100% oil. So the three new wells will be selling 100% oil. So the three new wells would be 100% oil. Plus at about $0.50 to $1.

Leo Mariani - RBC Capital Markets Corporation

I guess looking at the Spraberry, obviously, you guys have a new chart out there in your presentation. You addressed in your prepared comments as well about recent wells roughly five months of production history in showing the increase in production rates as this point in time. I'm curious to know how many wells are in that sample or whether or not that you think that sample of wells is pretty much tested was up to their acreage there?

Timothy Dove

But if you look at the graph there, Leo, in the fifth month, there's only a sampling of 55 wells. If you're in the first month, there's substantially got larger number of wells.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

And those 55 wells are pretty well distributed around your acreage?

Timothy Dove

Sure, absolutely.

Leo Mariani - RBC Capital Markets Corporation

In the Eagle Ford, just curious, obviously of the prelaunch position there. You've kept a fair number of us at this point in time. Just try to get a sense of kind of roughly what percentage of your acreage that you yourself or industry have kind of derisk with drilling results this point in time? Are you feeling pretty confident a lot of that this acreage can be put off? I'm just trying to get a sense of the risk factors there?

Timothy Dove

That's right now, Leo, because we haven't drilled between some of these wells. But if you look at the geographical swap of the wells, we would say we're pretty in that comfort having proven that say 75% to 80% of the acreage. On another area, 25% we had to drill some more Wells.

Operator

Our next question comes from Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch

Can you talk about in the Mid-Continent gas versus flat quarter-on-quarter? Can you talk about what is keeping it roughly steady if you're not drilling there?

Timothy Dove

This is a heavy operational focus for us, Gil, and in that particular area, it has to do with really attention to detail, it has to do with optimization and compression, it has to do with chemical treatment on oils, it has to do with doing some workovers where applicable, so it's basically the nuts and bolts of the business, and we've got just outstanding group of people there or who work on this project everyday to keeping these wells producing. So you would expect dramatically higher declines if you're not paying attention to detail, but this regards essentially keep in production flat, paying attention to those details.

Gil Yang - BofA Merrill Lynch

Can you give us an idea on how much capital you're spending in the area or if some of those built into the LOE against the [indiscernible].

Timothy Dove

That's LOE, our capital budget to Mid-Continent various less than $10 million combined Hugoton and West Palm [ph].

Gil Yang - BofA Merrill Lynch

For the year?

Timothy Dove

Yes. Pretty shocking, isn't it?

Unidentified Analyst

That's pretty good. But I think in the second quarter you also had some facility added downtime. Is the reason for some of the flatness in the area sequentially that the facility down -- the facility came back online in the third quarter and so production sort of ramped up but then there was decline offsetting that?

Timothy Dove

Well, I think what amounts to is, I won't speak to specific aberrations in the production but suffice it to say, you got to look back to the time and you'll see that we've been done exactly the same thing for several years, which is mitigating production declines and depletion just by activity and field activity. So I don't think it was an aberration quarter-to-quarter to say that one quarter we had production down, and the next when it came back up, as mush as it is, as I mentioned earlier attention to detail.

Gil Yang - BofA Merrill Lynch

Would it be reasonable to assume that you could keep it flattish for a while? Or is this sort of is all that attention that you talked about fairly somewhat lumpy and that it can hold it for maybe a quarter but then it declines again and do something?

Timothy Dove

Well, I think, if you look at our performance, you would find looking back to history, what we can do to is mitigate this depletion and decline to about a mid-single digits per annum. This is attribute to our Raton teak, our Mid-Continent teams and our South Texas area teams for making that happen. So I would say, overall, it looks like a mid-single-digit decline rate that we can land on, it probably double that if you weren't paying attention to detail.

Gil Yang - BofA Merrill Lynch

And turning to the Combo Play at least in period. Are there any other oil legs that you think that you could build up to prop up your school so to speak? The combo play, the Eagle Ford, you have the Permian. Are there other opportunities you see people are finding new oil place all over the place?

Scott Sheffield

Gil, with 22,000 locations in the street plays, I don't think we need anything else to prop us up. So it's all about execution hitting the 15% production growth. Obviously, we've been amazed by it's been about four to five recent deals in the Permian and the Spraberry. People are starting to pay $15,000 to $20,000 per acre. And when you got $10,000, $40,000 and another $15,000, $20,000 on twenties, people out there are paying $15,000 to $20,000 per acre. So it's so competitive. So we don't need another play.

Gil Yang - BofA Merrill Lynch

Can you just talk quickly about the Combo Play in the sense that other people have been in there for two or three years now. The acreage cost seems to be in compares to the $15,000 to $20,000 figure you decided that maybe up to $1,000 or so, what are people missing there that you're seeing?

Scott Sheffield

Yes, what happened out, the way I explained it the EOG started so early and made such a big lane graph. They have probably 80% of the acreage in the area, we're running 16 rigs. And so hen you have to look at Devin, Conoco Phillips to couple Devin two or three. We have one rig and so it took us 15 months just to build up the 15,000 acres with 75 to 100 land brokers. So they picked up the entire positioning and so that's why people can go in and get a dominant position. There's a very few other players that are there that people can buy. Where in the Wolfberry, you have a lot of private independents that are selling out and building under there production, they're selling out. So you can go in there and pay $15,000 to $20,000 per acreage. But it's dominated by one player, and that's the driver, that's the different and that's why acreage cost we only have a couple people leasing, that's why our acreage costs, we only a couple of people, that's why acreage cost haven't gotten out at hand.

Gil Yang - BofA Merrill Lynch

So you had to pick up the acreage on much more sort of sort of small particle'?

Scott Sheffield

Very small pieces, a lot of hard work.

Timothy Dove

And focused on probably a of specific areas.

Operator

Our next question comes from Rehan Rashid with FBR Capital Markets.

Rehan Rashid - FBR Capital Markets & Co.

Going back to the Spraberry really quickly. The 55 bells that we sited, does that include all of them go down to the Strawn?

Timothy Dove

Most -- only a few, a handful, what actually when actually when into Strawn because that Strawn drilling has mostly been done within the last five months. So you remember we started stock at about just Strawn only a matter of few months ago so most of I'd say essentially all of that 55 have been into Wolfcamp, but only a handful into the Wolfcamp, but only a handful in the Strawn.

Rehan Rashid - FBR Capital Markets & Co.

So we could see a little bit more improvements on this production curve as you blend in more Strawn wells?

Timothy Dove

I would say, that's right, where it's applicable of course.

Rehan Rashid - FBR Capital Markets & Co.

On the Spraberry vertical wells, how long is it taking to drill and complete down to the lower Wolfcamp and then down to the Strawn?

Scott Sheffield

We're still running about, I think we publicize this in the past about 1.8 wells per month per rig.

Rehan Rashid - FBR Capital Markets & Co.

And that would include you going down to the Lower Wolfcamp and Strawn?

Scott Sheffield

That's drilling time, it's not included in the completion.

Rehan Rashid - FBR Capital Markets & Co.

The frac-ing on the vertical part of the play is can anything different the done there? Maybe tighter curves or something more boring from today's completion methodology to improve that productive a further war that's kind of on the vertical component that?

Timothy Dove

Yes, I think first of all outstanding team of a engineers working on that exact question and we're trying a lot of different things. For example, even using coil tubing applications for frac-ing. So we're all over that question because needless to say, as we're staring in the face of third-party cost increasing, number one, we're doing vertical integration. But number two, we're always in the direction towards improving and reducing cost and so we have a lot of R&D going on as you cited new completion techniques in that field.

Rehan Rashid - FBR Capital Markets & Co.

And one last one on the on the same subject but just from. Standpoint, so Upper Wolfcamp only historical 60 barrels a day, 30-day average. I think in the second quarter earnings call, you've mentioned that lower Wolfcamp only added 25 barrel and then maybe a strong only added 70 barrels a day. So if I add all those three kind of components up, I'm much North of your 30% improvement, closer to a 150 plus kind of number for IT combined. Should I be thinking about that math a little bit differently?

Scott Sheffield

Yes, you have to. Because we have not increase the size of the casing or the pumping units. So some of these well, that's why we need more time. But we cannot pump the wells off. And so it's just going to take time to see we don't get those type rates initially. And the rates are averaging on the recent wells with all Strawn 80 to 100 to 110 barrels per day. And so the initial rates so we're staying flatter. And that's why we need more time to pumpies wells off, see what they're going to do long-term.

Rehan Rashid - FBR Capital Markets & Co.

So 100 to 110 when you try to produce all three together and maybe staying a bit flatter?

Scott Sheffield

That's right. We're not using hydraulic jet pumps like some operators that pump up wells.

Operator

We'll take our next question from Joe Allman with JPMorgan.

Joseph Allman - JP Morgan Chase & Co

A follow-up on the Spraberry play, in particular in the cost. So in your slides you indicated that the cost are $1.2 million to $1.3 million. Can you just clarify, is that the cost of the most recent wells, including the deepening, and with the deepenings, where do you think that cost can get to even considering kind of the pressure from the third-party frac companies?

Timothy Dove

Yes, Joe. You cast it correctly when you first said that it is reflective of the deepening of the wells. So today's cost is about $1.2 million to $1.3 million, which reflects the deepening of wells into the lower Wolfcamp and the Strawn. Looking forward, I mentioned earlier regarding the third-party pressure pumping price increases we're trying to achieve, it would lead to perhaps $200,000 to $300,000 increases in the oil cost looking forward to 2011 for those who are highly dependent on third parties. Of course, as I mentioned earlier as well we're going to have four frac fleets out there and by the second quarter, so we will be not 100% self-sufficient but close to it in 2011 for pumping our own wells. Associate with that, we should be expecting lower oil costs dramatically the main one is going to be used third parties. And that's where we site the 200,000 to $300,000 potential savings by completing our own wells.

Joseph Allman - JP Morgan Chase & Co

Do you think you can get these costs from $1.2 million to $1.3 million down to $.02 million to $0.3 million?

Timothy Dove

Here's the way I should think about it. The markets for 2010 was in this range of about $200,000 to frac wells, frac-ing complete wells. And so, when we cited the $1.2 million to $1.3 million per well cost in 2010 with the deepening of wells, that includes a frac for about $200,000 to $250,000. That end what's happening is you're seeing an increase being requested or demanded I guess you can say from the service companies put additional $200,000 to $300,000 for 2011. And so it's the case that you don't necessarily cut from the $1.2 million to $1.3 million but you would have to be able to maintain close to that. We'll probably see some creep on the rig cost as well in 2011. So instead of being $1.2 million to $1.3 million, maybe $1.3 million to $1.4 million for that wells that we're pumping ourselves. If you rely on third-party pumpers, the costs are going to be a $200,000 to $300,000 higher than that for the same exact well.

Curtis Trimble - MKM Partners LLC

And on a long-term basis, do you think $1.3 million, $1.4 million is that a better number to use?

Timothy Dove

For us, it is, for 2011. If you're dealing with others and the trend, there going to be playing $300,000 more than that.

Joseph Allman - JP Morgan Chase & Co

And then with the Eagle Ford, earlier this year, you're doing a lot of science and costs rate to $10 million. Now you're saying $7 million to $8 million, and if you're achieving efficiencies early in the cycle and you thought, do you think you could get those costs down as well from $7 million to $8 million ?

Timothy Dove

Well, I think the next steps are going to be related to bringing your own frac fleets in. Our own frac fleet will be in there in the second quarter. I think we can pump these wells for $1 million less than the third-party alternatives, and so when we're saying $7 million to $8 million. That's reflective of generally speaking third-party costs today and the costs are only going up. So I think suffice it to say, we can bring the oil cost down, but at the same time, we are seeing some creep across the board. So I think what you're really saying is we're going to have a very large competitive advantage compared to our peers in terms of drilling costs in both of these areas.

Joseph Allman - JP Morgan Chase & Co

So longer-term, is $7 million to $8 million probably a good number to use or you think you can actually [indiscernible]?

Scott Sheffield

I think that's okay to use, $7 million. I mean that's kind of where we've been landing the cost. Our whole objective is to reduce it below that, but we need to get our own frac fleets out there, and then we'll be able to land but what we can do it for and we'll heavily publicized that when that happens and say second quarter next year.

Joseph Allman - JP Morgan Chase & Co

And then so with the cost issue and vertical integration, are there any areas of particular tightness that require you to really step it up and make sure you get additional capacity?

Timothy Dove

Well I think one of the questions that we'll face is in relation to both Permian and Eagle Ford shale is that we got substantial ramp ups in drilling coming in both in 2012. What you hear us saying is in 2011, we feel very comfortable where we are in terms of being able to supply all our internal services and at work with third parties to get our work done. 2012 with the ramping up campaigns, we're definitely make a decision, do we want to provide our own pumping services to increment that oil comp in those years and that's something we can decide later this year.

Joseph Allman - JP Morgan Chase & Co

And then lastly to the Barnett Combo, how many results do you have so far? And I'm not sure, have you released any results?

Timothy Dove

We're drilling our first well as we speak so we don't have the results reported, and we're probably won't have any results until our fourth quarter call.

Operator

And your next question will come from Michael Hall with Wells Fargo.

Michael Hall

Just quickly in the Eagle Ford, you talked about the most recent wells kind of bringing your choke sizes down a bit. Can you provide any insights into the thinking there?

Timothy Dove

Well I think the feeling is especially having to look at the results of the Haynesville earlier on, we've been protective of our wells, and I think it's the case that we're beginning to see some impaired evidence to say that, that's the smart thing to do even in the Eagle Ford even though our rock is substantially harder than it is in this Haynesville. We saw some positive things coming out of our current well performance to say not pulling on the wells too hard to have a very positive effect on the ultimate reserves, your ultimate EUR in the wells. And so that's just part of the program where we're being prudent and careful to make sure that we are handling these wells in fashion that's safe in terms of protecting our long-term EUR.

Michael Hall

And then so any of the wells that have been on the longest, have you seen any increases in EUR yet or any...

Timothy Dove

Now we're seeing basically sort of the same EURs as when we first put it on production.

Michael Jacobs - Private Investor

And no retro rig count issues as of yet?

Timothy Dove

We don't anticipate any retro rig counts that issues in our field. We have such high temperatures, pressures and depth that if you steady phase diagram analysis is extremely low probability, we have many retro rig kind of issues because of that combination of factors which and the physics has really helped us keep the retro rig counts and save issue to be basically at minimum.

Michael Hall

And then moving up in the Spraberry, if you think you would have the ability and a positive vision with the upcoming reserve report based on the deepening set or is it too early on a proven basis?

Scott Sheffield

It kind of remains to be seen where increment reserves because of the deepening. We need some more time as we've already said to decide whether or not to or when to increment our tight curve for instance, we're talking about holding early next year. So that's as yet undecided for year end whether it'll bump reserves because of deepenings, let's just get back to you as we decide where we're going to land that at the end of the year.

Michael Jacobs - Private Investor

And on the horizontal Wolfcamp, have you provided cost spendings for those two wells?

Timothy Dove

Yes, there are several multiples of vertical. That's kind of where we'll land on that one.

Michael Hall

And then how many completion stages are you doing?

Scott Sheffield

The question was how many completion stages in the horizontal?

Michael Hall

Yes.

Scott Sheffield

Yes. Our current plan is about 14 in each of the two wells.

Scott Sheffield

And then, Scott, you talked about seeing some big bio breaker value transactions on the Permian. I recognized it's a much material asset than the Eagle Ford and strategically, different assets for the Pioneer. Have you ever thought about similar debut transactions that you get in the Eagle Ford or in the Permian or any scenarios there that might make sense?

Scott Sheffield

Yes, obviously, with the big pickup -- when people start paying $15,000 to $20,000 per acre, we start asking ourselves questions, is there enough universe out there to continue that trend? And is there any interest? There has not been any JVs to my knowledge. These are all complete divestitures by -- or land acquisitions, about these parties so it does raise a question and obviously, we're discussing that at the management level and at the Board level over the next several months.

Operator

Our next question comes from Daniel Morrison with Global Hunter.

Daniel Morrison - Global Hunter Securities, LLC

A follow-up on the Spraberry kind of cost controls. Could you take us upstream on the supply side a little bit on sourcing for all those pumping units and tighten whatnot?

Timothy Dove

Yes, Dan. I can't give any details, obviously regarding how those contracts look. But suffice it to say, we don't really see any real substantial increase in cost on those purchases for 2012. 2011 was already in place.

Daniel Morrison - Global Hunter Securities, LLC

Are you sourcing those domestically or international or combination?

Timothy Dove

We'll get into a lot of detail on that, but it's really a combination.

Operator

Our next question comes from Mitch Wurschmidt with KeyBanc.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

Can you just give -- you talked a lot about the enhancement on the Spraberry curves and can you talk a little bit about the returns look like under that? Scenario the 30% sort of increasing [indiscernible] production?

Timothy Dove

Well, needless to say, we're going to see a dramatic increase as we get 30% incremental production. At the same time, as I mentioned earlier we're in a season cost creep that comes as a result of the increases in drilling rigs and to the extent that we have to use any third-party services. I think what that will lead to is a conclusion that we can continue to land to about 50% rates of return which at a minimum which includes 30% incrementally and more production and offsetting that was some cost creep, but can maintain kind of where we are today.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

That sort of the minimum, I guess as you're thinking right now?

Timothy Dove

That's the current thinking.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And then for Tunisia, can you give any more color on sort of what production look like maybe for 2011 just sort of assuming not really looking at the wells are going to be drilling but just sort of what it would look like under the current scenario?

Scott Sheffield

Yes. First quarter, we're targeting 8,000 to 9,000 barrels a day. So we've averaged somewhere between a little bit over 5,000 this year, 5,000 as we've mentioned. And so it's going to put the number up somewhere, the big factor is what type of CapEx are we going to give Tunisia going into next year. And where we go to target. So at this point in time, it's hard to give out a number, but obviously, it's going to start up fairly strong going in the first quarter 2011.

Mitchell Wurschmidt - KeyBanc Capital Markets Inc.

And I guess on the lower Wolfcamp, you just mentioned towards the southern part of your acreage just being a little more cautious towards that part of the acreage or I guess, below that further South. Anything you can point to down there that sort of looking at that I guess you get a little more cautious for that area?

Timothy Dove

Well, I think we'd point to specific well control. We do a lot of wells down in the southern part of our acreage and we think prospectivity is less going in that direction. So this isn't anything other than well control.

Operator

Our next question comes from Ken Carroll with Johnson Rice.

Kenneth Carroll - Johnson Rice & Company, L.L.C.

In terms of the combo play about real quick, you have one rig there, it sounds like you're in some other non-operating wells. Just where do you see the capital going in this play in 2011 beyond? It seems to be very good returns below what you'd see in the Eagle Ford or the Permian. It seems like it's -- might be low tough competing for dollars, how do you see the rig count in 2011 looming up?

Scott Sheffield

Yes, a lot of it depends on where our CapEx comes in with our cash flow going into next year. And so we would like to get up to four rigs at some point in time. We don't know if it'll be by the end of '11 or '12 but the play is designed to move from one rig up to four rigs over the next couple of years. We just can't exact pin down. We want to see some positive results from the one rig, and I'm guessing over time, we'll layer up to four over the next 24 months.

Kenneth Carroll - Johnson Rice & Company, L.L.C.

And if I heard you correctly, it sounds like just given the competitive nature of their, how much acreage is locked up while you're still adding acreage? We shouldn't see a huge incremental increase in acreage going forward?

Scott Sheffield

No, we're only targeting picking up another 10,000 to 20,000 at the most acreage. So it's about as much as -- it's about where we are going to stop at.

Operator

There are no further questions at this time. I'll turn the call back over to Mr. Sheffield for any additional remarks.

Scott Sheffield

Again, thanks. Thanks for all the questions about our key assets. Looking forward to the next quarter. I think Spraberry is obviously outstanding performer this quarter. We'll continue to outperform and then we'll talk obviously a lot more about Eagle Ford as we see a lot of our wells starting to come on production as Tim talked about. We're going to be the obvious a major focus in February. Again, thank you and we look forward to the next call.

Operator

And ladies and gentlemen, that will conclude today's presentation. Thank you so much for your attendance. Have a great day.

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