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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

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

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

Eliecer Palacios - Maxim Group

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

John C. Nelson - Macquarie Research

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

Scott Wilmoth - Simmons

Marcus Talbert - Canaccord Genuity, Research Division

Pioneer Natural Resources, (PXD) Q1 2011 Earnings Call, May 04, 2011 May 4, 2011 10:00 AM ET

Operator

Good day, and welcome to the Pioneer Natural Resources First Quarter Conference Call. Today's call is being recorded. 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 our comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select "Investors" then select "Investor Presentations".

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

Thank you, Shannon. Good day, everyone, and thank you for joining us. I'm going to briefly just go over the agenda for today's call. Scott's going to be the first speaker. He will provide the financial and operating highlights for the first quarter of 2011, he'll then comment on the company's production outlook, capital program and cash flow forecast for the 2011 through 2013 period. After Scott concludes his remarks, Tim will update you on our drilling results and plans with particular focus on the Spraberry, the Eagle Ford Shale and the Barnett Shale Combo Play. Rich will then cover the first quarter financials in more detail and provide earnings guidance for the second quarter. And then after that, we'll open up the call for questions.

So, Scott, I'll turn the call over to you.

Scott D. Sheffield

Thanks, Frank. Good morning. We appreciate everybody's time to listen to our first quarter call.

Again, we had an excellent quarter. First quarter 2011 adjusted income of $81 million, or $0.68 per share. It does exclude our gain from our -- primarily from our Tunisia sale that happened in first quarter, and also unrealized mark-to-market derivative loss of $164 million primarily due to the run up of both gas and crude.

Production. A little over 111,000 barrels of oil equivalent per day, primarily impacted by the cold winter-related downtime in Mid-Continent, Spraberry and Raton, about 2,000 barrels a day. And also, unplanned third-party downtime in Mid-Continent, Alaska and South Africa of about 1,500 barrels a day.

Our Spraberry program is on track and expanding. We're already operating 32 rigs, on track to be at 35 by midyear. And stating that we'll be at 45 by the end of this year going to 2012.

We're operating 4 frac fleets, increasing to 6 frac fleets this month, 7 at year end. I think the important point of increasing these frac fleets is we have finally got on most of our frac fleets in both Spraberry and Eagle Ford, which you will see. Tim will go into great detail about the number of wells completing, increasing significantly going to second, third and fourth quarter of 2011 in both Spraberry and also Eagle Ford.

Our early 20-acre well production is exceeding expectations, so a 110,000 type curve that would come out. We're already seeing significant increases and expectations. And I think we only had about 3 wells that went to the Strawn, so most of it's due to the Spraberry shale zones and the Wolfcamp -- is causing the production to exceed expectations of the 110-type curve.

Also our Strawn wells are continuing to add significant production and reserves. We're now completing our first 2 Atoka wells, Tim will talk more about those.

And then finally, as we have stated in the last several weeks, we have an R&D program to test about 4 different zones in both the Spraberry and the Wolfcamp, of horizontal wells.

I'll be releasing information on our first 2 wells. The carbonate well, we frac-ed out a zone. It came in at about 100 barrels a day. Frac-ed out a zone in that well. Obviously, we're going to drill 2 or 3 more wells in various areas in the carbonate. And then our second well, I'm very highly encouraged the fact that just after about 10 days, it's producing 150 barrels a day, still producing 1,000 barrels a day of load water with strong flowing pressure.

We are planning to drill another 6 to 8 wells, primarily this year. We'll continue that program going to 2012. And the long-term goal in the next 2 years is drill 3 or 4 wells, what we call a "pilot program" into each of these 4 key zones.

To date, we have not seen any evidence at all from other operators. Obviously, from ourselves, it's too early from other operators, that our testing horizontal Wolfcamp wells that exceeds our vertical program of 50% returns in our vertical program of 700 wells this year and close to 1,000 wells next year.

Eagle Ford Shale production ramping up. We're operating 9 rigs, on track to be at 12 rigs by midyear. Again, we initiated 2 frac fleets in April. Tim will go over great detail. You'll see the significant number of wells that will be completed and put on production over the next 3 months -- or next 3 quarters. Expect to be a 3-frac fleet by year end.

Barnett Combo play. With 2 rigs running, very consistent with our type curve of about 320,000 barrels of oil equivalent. We've already drilled 24 wells drilled, 5 are producing with excellent results.

Again, to remind everybody, we closed our sale of Tunisia for $866 million. Proceeds will be used to redeploy the core U.S. assets, primarily Eagle Ford and Spraberry ramp-up, over the next 3 years.

Again, a great, strong balance sheet with debt-to-book going down at 31% at the end of first quarter for 2011.

Going to Slide #4, next page. Still targeting 18% compounded annual production growth. We're confident that we're going to hit that number over the next 3 years. And we're also confident that we're going to hit a range of 125,000 to 130,000 barrels. It's primarily due to the significant ramp up, or bringing on these frac fleets in second quarter. Continuing to increase those and seeing a significant completion ramp up, primarily both in Eagle Ford and Spraberry.

Guidance for second quarter, 116,000 to 121,000. So a significant increase from the first quarter. And obviously, again, significant increase going into the second half of 2011. Liquids production continue to increase, going from 44% up to 55% by 2013.

Going over our CapEx. Drilling capital still at $1.6 billion. Obviously, it's primarily focused on the Spraberry trend area field. Vertical integration facilities, about $200 million. We'll be completing most of that this year. Again, the capital program funded primarily from the cash flow of about $1.5 billion, and using about $300 million of Tunisia sale proceeds.

Slide 6. Again, due to the fact that we're bringing on high liquids, much higher margin by increasing our liquids production. Cash flow significantly aids our growth, but we're going up to $2.1 billion for 2012 and up to $2.6 billion, as shown on Slide 7, for 2013. When you put that together, we're over 30% compounded growth rate over the -- since 2010 to 2013.

As we have stated, our CapEx will be close to these numbers going into 2012 and 2013. The increase, primarily due to the Spraberry ramp-up in 2012, and due to the fact that carry in Eagle Ford will go away. During the first quarter of 2013, we'll be picking up our share in the Eagle Ford play.

On the last slide. On Slide #9, again, we have over 20,000 drilling locations. Obviously, that number will go up with the success we're seeing in the 20-acre drilling. Right now, we're just putting out the number of high-graded 20s, but with the 20s so far exhibiting greater than 110,000, that number will continue to go up over time. Again, tremendous acceleration, drilling and completing in the Spraberry and Eagle Ford Shale zones.

The redeployment of our proceeds allows us to accelerate even further. Again, showing 18% compounded growth rate for '11 to '13, and cash flow growth of 30% plus during that same 3-year timeframe. Again, attractive hedging positions and vertical integration allows us to protect our margins. And again, we're ending the quarter with a very strong financial position and great balance sheet.

So let me turn it over to Tim to go into more detail of our operations.

Timothy L. Dove

Thanks, Scott. And here at Pioneer, we continue our heavy focus on execution. And it is now paying great dividends that we entered into the strategy of vertical integration a couple of years ago. Because it's not a case that we're increasing our control of our own destiny.

And as Scott has already mentioned, we've a accomplished a lot in terms of adding frac fleets. One year ago, for instance, we only had one frac fleet. And as he mentioned a minute ago, we'll have 6 here, during May, operating on behalf of the company. In addition to which, we've added quite a number of dedicated fleets. And so we're well on our way to see a very significant ramp-up in wells put on production. I've got some very detailed slides on that coming up. And that will lead to substantial increase in production, particularly as we ramp up in the second half of this year.

I'll start my commentary on Slide 10 with a discussion of the activities in the Spraberry field in the Permian Basin, where Pioneer has the dominant position in the Basin. We have about 50% of the acreage in the basin, and the vast majority of that is held by production. What we continue to observe is a big field getting bigger as a result of our activity. And that will continue, with some 20,000 drilling locations ready to drill. We're the most active operator in terms of rig count in the Permian Basin.

Turning to Slide 11. And this is covering some of the comments Scott made on the deepening program. That's starting -- or in the position right now, we can start to compile some definitive results, that we are in fact, significantly enhancing our rates and EURs by virtue of deepening the Spraberry wells.

So firstly, let's talk about the Strawn. And the Strawn, of course, sits directly below the Wolfcamp. We've now completed 38 vertical wells in the Strawn over the last 5 quarters or so. That last 200 feet that it takes to drill into the Strawn only cost about $60,000 to drill. And of course, in addition to which is one frac stage. And what we're seeing is very substantial in the sense that the results indicate that we're getting about a 20% increase in first year production compared to wells that are TD-ed within the Wolfberry itself.

And in terms of EUR contribution, we believe it is in the neighborhood of 20,000 to 40,000 BOE that we're adding in terms of Strawn. In terms of the prospectivity, we believe it covers about 40% of our acreage. And about 50% of this year's program will target into the Strawn.

As for the Atoka, we're just starting up an Atoka program. It sits below the Strawn. It calls for us deepening the wells another 500 feet, since it sits about 700 feet below the Wolfcamp. And that will add about $500,000 to $750,000 per well. The plan, of course, is to drill a series of Atoka wells. We're completing our first 2 wells as we speak. After testing those wells, we'll later co-mingle the Atoka zones with the upper intervals of the traditional zones to be perfed and completed in Spraberry-typical wells, including the Wolfcamp.

What's happening, of course, is the idea of adding substantial reserves also applies to Atoka. And in this case, we believe based on some deepened well data from offset operators in the area, there's a possibility to add something in the neighborhood of 50,000 to 70,000 barrels of incremental EUR to the deepened well. So that gets your attention. And as a result, we plan to test about 10 to 20 wells into the Atoka during 2011. And of course, we'll be reporting more about that as we see the well results. In summary, our well deepening in the Spraberry trend area is showing excellent potential in EUR adds.

Turning to Slide 12. Here's an update on 2 existing projects. Our 20-acre down spacing, as well as our Waterflood. We've now drilled -- we drilled 18 wells in 20-acre locations in 2010, 14 of those are on production. Importantly, only 3 of those were drilled to the Strawn. Scott mentioned that in his earlier comments. So in essence, a lot of what I'll going to talk about is really pay that's coming only from the lower Wolfcamp and upper zones, as opposed to Strawn. Strawn has the potential to add even more. But what's very important to note is that the 20-acre drilling campaign that we've seen so far is yielding results that are outpacing our old type curve. The 110,000 BOE type curve that we had in place for 40-acre traditional Spraberry/Dean drilling has now, of course, been increased to 140,000 barrels to include the Wolfcamp. Now we're exceeding that 110,000-barrel plan, without in most cases, completing in the Strawn. And that gives us a lot of encouragement about what 20-acre drilling can do now and in the future. And accordingly, we'll be drilling 20 wells or so in 2011 that will also be focused on more data for our 20-acre campaign, where we have some 13,000 future locations or more to drill.

The Waterflood project continues in the 7,000-acre pilot we put in place last summer. The production declines in that project area, where we have a little over 100 wells producing, continues to flatten. And the early production response is being seen, actually, in quite a number of wells. And so this is working out quite well. We're very confident that we're seeing positive results out of this. It's a little bit early to give final results, because ultimately, we're looking for an uptick in production from the flooded zone, that being the upper Spraberry. The 20-acre drilling and the Waterflood project, again, our efforts that are focused on improving recovery efficiencies in the field going forward.

Turning to Slide 13. And a discussion here surrounding the Wolfcamp horizontal activity. Scott has already covered some of this. Slide 13 shows the zones that are being targeted by various other operators. I won't go through these in detail other than to say that our wells, as shown in green, target the Wolfcamp carbonate and also the lower Wolfcamp shale. And as Scott has already alluded to, we'll be testing several of these other zones, including the Tippett shale and the Jo Mill, and future wells as we roll out our pilot project.

As to the results of these wells so far, that's covered on Slide 14, the first 2 wells in our horizontal pilot program. Both of these wells were drilled with approximately 4,000-foot laterals, about 15 stages of fracs. We did add microseismic in both cases such that we could monitor the fracs in each case from offset wells. As Scott has already mentioned, the first well IP is about 100 barrels of oil per day, but we didn't have an effective stimulation as an out-of-zone stimulation. And as a result, the production declined. We don't believe this is really representative of a test in this zone. And likely, we'll be drilling future wells to properly test the zone.

The second well, which was, as I mentioned a minute ago, completed in the lower Wolfcamp shale, is now in the process of unloading. The well is about 30% unloaded, and we're seeing early test rates of about 150 barrels of oil per day. This well, just so you know, is naturally flowing upcasing. And actually, it's starting to produce gas as well. As a result, the rate I mentioned a minute ago is really not an IP rate, that's simply an early test rate on this well. We'll be getting more information out when we finally IP the well after the flowback has occurred. It should take us quite a bit of time to have all the water unloaded from the well.

We are going to continue a pilot program, as Scott mentioned, to drill several more wells in various different formations. This is an R&D project for us, and so we're going to take quite a bit of time and effort and money to test various different zones. And this will probably stretch well into 2012.

Turning to Slide 15. I mentioned in my first commentary that this vertical integration business that we've entered is really adding a lot of value in today's world where the services are very tight. And we're industry leader in vertical integration, which allows us to control costs and enhances our ability to execute. Today, we have 14 of our own rigs working in the Permian out of a total of 32, for instance. We are significantly increasing our frac ownership as well as dedicated fleets. And we have a bunch of our other supplies and materials in place on long-term contracts, including a new item where we're planning to contract our cementing services for the next 5 years.

All of this activity has the effect of saving significant amounts of money. In fact, the savings for the vertical well program is about $500,000 per well, which gives us a significant advantage in the total blended cost of our wells, and then preserves the rate of return, being approximately 50% before tax. We'll continue to take steps to mitigate execution risk wherever we can and to control costs, and our vertical integration program is doing just that.

On Slide 16. This is a lot of detail, but it give us a lot of granularity, in fact, on what we expect to result this year in terms of putting new wells on production. Ultimately, this is the most important statistic about how our production should grow, is how fast we put wells on production. And it gives us confidence in our ability to accelerate production because we have the fleets in place where they're coming, and that we have a very detailed plan to accelerate the number of wells put on production.

And we show it here by quarter. As the new frac fleets come in, where it will be -- get up to 35 rigs middle part of the year. We had frac fleets both in the second quarter. We'll be having some spot fleets added in the third quarter. And our own fleet, our fifth own fleet, adding to a total of 7 in the fourth quarter.

So this gives us a lot of confidence then to point to Slide 17, which shows the production effect. And you can see, really, a dramatic increase in production. Our production has been -- when we're in acceleration mode as we are both here in the Eagle Ford Shale, we have a back-weighted result because we're just in the process of getting the fleets in place, getting the wells drilled, accelerating the numbers of wells drilled. So we have a back-weighted, second-half-weighted production growth in both of these key areas as we accelerate.

But ultimately, we're confident in the 25% growth rate looking forward through 2013. You'll note on the bottom of Slide 17 that we have a schedule for 45 rigs beginning 2012. Many of those rigs are already contracted -- almost all of them are already contracted. They will be in place by the end of the year. We'll be at 35 here very shortly, from 32 currently. So we're very confident in this asset. Again, we do not drill dry holes here. It's just manufacturing oil, and we have in place the processes to execute on the plan.

Turning now to Eagle Ford Shale, Slide 18. Our operations are progressing very nicely there. We have 9 rigs running. We'll have about 12 here shortly by midyear. All of the operations are going exceedingly well. We have a couple of new things in the slide here that we haven't discussed before, at least as to an earnings call. And that is that we are testing white sand as a proppant in some of our shallower areas of the field, principally to the northwest, we're drilling shallower wells. And the fact is, if we can use white sand efficiency, when it seems like some of the early results show that we can, we would have significant savings compared to ceramics, in terms of the proppant being used on these wells.

Our well performance continues as expected. In fact, in some areas, better than expected. Of course, we're drilling up and down the trend here, not necessarily as efficiently as we will when we go to development mode, when we can drill from individual pads a series of wells. Today, we're still in the preservation leasehold mode drilling up and down the acreage. But that gives us a great deal of confidence in the aerial extent and quality of the area we are. We still believe we're really in the sweet spot of the Eagle Ford Shale.

We get a lot of questions regarding the Petrohawk wells in the Black Hawk area, which offsets a lot of Pioneer acreage DeWitt. In fact, we're seeing well results that exceed our internal type curve for the high-condensate yield area which this represents. So we can confirm that Petrohawk's information as to how the wells are doing in that area, that's also being seen in our area as well.

We are ramping up our execution capabilities. As you know, we were a little bit slow getting some frac fleets out there in the first quarter, but we now have our own and a third-party fleet operating at a high level of efficiency in the field. We have now 5 central gas processing facilities in place, and we'll have 3 more done by the end of the year. And so what you'll see, of course, is just like we saw in Permian: a significant increase in the number of wells we put on production.

And on Slide 19 is the identical slide I showed for Spraberry. It shows the ramp-up of wells we'll put on production in the Eagle Ford Shale. And you can see that it really is a reflection of initiating the new frac fleets.

It's also related to getting the CGPs in place. And what it leads to, just as we see in the Permian, is a significant acceleration both in wells put on production, and therefore production itself, especially in the second half of the year. That's specifically shown on Slide 20, where you can see a dramatic ramp up as the execution takes hold. And in addition to which, of course, we're increasing the rig count. We'll be at 12 here shortly. Going to 14 is the current plan for 2012, and then 16 for 2013.

Turning to Slide 21. I'll be brief about Barnett Shale. We're starting to see our first production results from the drilling campaign we began at the end of last year, and we're very encouraged at what we are seeing. And we currently have 2 rigs running. Out of the 24 wells that we've drilled, we have now 5 of those producing. And we're seeing very good results. The last 3 wells that we put on production, for instance, the data is showing here on the slide, averaged about 155 barrels of oil a day, 854,000 cubic feet per day. So really quite an excellent well result. And we estimate that, based on the type curves that we have in place, that these wells are meeting or exceeding those type curves, which is going to yield in the neighborhood of a 50% internal rate of return, based on current pricing.

Importantly, we have one of our own company-owned frac fleets that will be operational this month. And that will allow us then to, again, positively impact our growth as shown on Slide 22, depicting production growth from the Barnett Shale. And in fact, what you see in Pioneer is a very heavy focus on execution. We have in place an excellent plan to execute in all these critical areas, and it's going to lead to substantial growth in production, both as we get later into this year and going into the next couple of years as well. In fact, in Barnett Shale, we're looking potentially adding 2 rigs or more in 2012 and 2013.

With that, I'll pass it on to Rich for a discussion of the financials and his outlook for the second quarter.

Richard P. Dealy

Thanks, Tim, and good morning. I'll Start on Slide 23. As Scott mentioned, net income for the quarter attributable to common stockholders was $349 million, or $2.96. Included in net income are 3 items worth noting. One, as Scott mentioned, we had unrealized mark-to-market derivative losses as a result of the increase in strip commodity prices of $164 million after tax, or $1.40. We also recognized income from discontinued operations. This is predominantly related to the Tunisia sale and recognizing a pretax gain of $650 million. So after tax, ARO [asset retirement obligations] in discontinued ops was $415 million. We also had $17 million after tax from Alaska Petroleum Production Tax credits for the quarter. So adjusting for those items and getting to a normalized earnings, we're $81 million, or $0.68 per diluted share

Looking at the bottom of Slide 23, our guidance, which does reflect our update that we did in guidance in March for the weather impact. If you look at our results, you'll see that each of these items came within guidance or on the positive side of the guidance down that list. So excellent quarter for the company.

Looking at Slide 24. The bars at the top represent our realized prices, so these do exclude VPPs and derivative impacts. You can see that oil prices are up in the first quarter relative to the fourth quarter 12% to $89.43. NGL prices on a same comparison is up 3% in the first quarter compared to the fourth quarter. And gas prices are up 10% to $4.14 as compared to the fourth quarter of $3.76. At the bottom of the slide, we do list out the impacts to pricing that we report from the VPPs and derivatives. So there they are for your review.

Turning to Slide 25, production costs. Spend a couple of minutes here. First quarter production costs came in at $13.31 per BOE. This is up from the fourth quarter. But as we mentioned back in February, the fourth quarter had a couple of items in there, the biggest one being a $10 million Alaska processing fee recovery that lowered our fourth quarter LOE by about $1 per BOE. We also had ad valorem tax accrual adjustment in the fourth quarter that resulted in production taxes being lower.

For the first quarter, a couple items there. In LOE, as we mentioned back in March, we did have a significant amount of repairs that hit in the first quarter to repair the damage caused by the severe weather. So that's included in our base LOE. And then as I mentioned on the previous slide with commodity prices up, our production taxes are higher in the first quarter.

Turning to Slide 26. And talk about guidance here. Production, as Scott mentioned, 116,000 to 121,000 BOEs per day. And as Tim talked about, the growth is significantly weighted to the second half of the year as we put on more wells on production during the second half. Production costs and really, the remainder of the items listed here are very -- are consistent, in fact, with past quarters. So I won't go through each one individually, but they are consistent with past quarters and how we did in the first quarter.

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

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from Scott Wilmoth of Simmons and Company.

Scott Wilmoth - Simmons

A couple of question on your company on frac fleets that you guys are adding currently and later in the year. Do you have all the staff lined up, and hired and trained, to make those operational as soon as you get delivery?

Timothy L. Dove

Yes, Scott. Actually, this is Tim. We're in the process of hiring the staff related to the 2 fleets that are coming the fourth quarter as we speak, and training them on existing facilities. Our hiring has gone exceedingly well. And what happens is people are very interested to work for an operator, for a producer, in certain ways, more than they would like to work for a service company. And so we're getting excellent response, and we're doing very well in terms of meeting our hiring plans.

Scott Wilmoth - Simmons

Okay, great. And then when I think about the second half ramp plan in the Eagle Ford, obviously, you got the frac fleets, you got the people. Have you guys lined out transportation and gathering needs for that ramp?

Timothy L. Dove

Yes. In fact, we're working very hard, of course, because this is a substantial amount of volume. We're working with various different parties on preparing for and being ready for liquids volume movement, in this case, condensate. Of course, our natural gas is -- and rich natural gas, in this case, is spoken for because of 3 separate contracts that we have for offtake. So I think we're in very good shape there.

Scott Wilmoth - Simmons

Okay. And then just jumping over the Spraberry. The Atoka, you mentioned 50,000 to 70,000 additional BOE, MBOEs per EURs that you're expecting. Is that in addition to the potential 20% uptick in the Strawn?

Timothy L. Dove

Yes.

Scott Wilmoth - Simmons

Okay. So if we think about we're at 140, potentially, up 20% in the Strawn, and then maybe another 50 to 70 with the Atoka. So ultimately, we could be at 220 to 240 EURs with like $2 million to $2.2 million well cost. Are we off on that?

Timothy L. Dove

I think those are relatively accurate. Realizing that, remember, it's not applicable in every single acre in the Spraberry trend there is only certain acres where that would apply, where we have a combination of Strawn and Atoka.

Scott Wilmoth - Simmons

And in Strawn, you guys said about 40%. And then how much Atoka do you guys think is prospective across? Is it just too early to know?

Timothy L. Dove

It's too early. I mean, this is our first 2 wells. And so we need to get a little data before we can really answer that specific question.

Operator

Our next question comes from Brian Corales with Howard Wheel.

Brian M. Corales - Howard Weil Incorporated, Research Division

With -- I guess, with only one frac fleet that you're -- or now at 2, I mean, how big of a backlog do you have in Eagle Ford in terms of uncompleted wells?

Timothy L. Dove

Right now, our frac bank is about 15 wells. We've been working into it on the basis of the Pioneer fleet and a third-party fleet that has been -- they've both been out there since April, and they've been very efficient. We are going to be having a few spot slots available from other operators who haven't got their wells drilled in the second quarter. So we're not -- we don't really talk about that because we really talk about our dedicated fleets, that's Pioneer-owned and longer-term contracted fleets. But we are picking up additional slots here and there to be able to meet that put-on production schedule.

Brian M. Corales - Howard Weil Incorporated, Research Division

And kind of with the ramp in both the Spraberry and Eagle Ford, I mean, how much of the -- do you want to have company-owned or completion crews out there versus -- or how do you think about with the ramp? Are you going to be buying new ones, or kind of leasing them out in the future?

Timothy L. Dove

I think we have stated -- in fact, publicly, we stated that the amount of vertical integration we do in any given area somewhat depends on how tight that market is. So for instance, in the Permian Basin, we're about 30% vertically integrated on rigs. There are rigs available. In the Permian Basin, though, we're heading more towards about 2/3 vertically integrated on pumping services because it's so tight. And right now, we're contemplating, of course, the delivery of an additional frac feet in Eagle Ford, which should put us essentially 2/3 vertically integrated in Eagle Ford, as well, by the end of the year. So that's kind of the rough percentages we're thinking about.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then one final question. And I think you talked a little bit about it on your comments, but in the Spraberry, I mean, how much of your drilling is holding acreage? Or is that just pretty much mostly done?

Timothy L. Dove

It's relatively minimal in the overall scheme of things. We're drilling 700 wells or so. We probably drill somewhere in the neighborhood of 150 wells a year to hold production in one form or another.

Operator

And Leo Mariani with RBC has our next question.

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

Quick question. Kind of changing gears a little bit on Alaska. It looks like your Alaskan production's been kind of sloppy the past couple quarters. I mean, you guys talked about some well maintenance as well in the second quarter, which kind of leads me to believe it might be down again. Curious as to when you guys expect that to sort of ramp up. And what kind of growth are you expecting out of Alaska?

Scott D. Sheffield

Yes, Leo. We've gone through the last 60 days, a recompletion program and some workover programs. And we should see a pretty good bump going into the second and third quarter of production. Also, we'll be bringing on -- we just started testing our Torok well. It's making over 900 barrels a day. That's at long lateral, the third zone. It'll be coming on here shortly. In fact, it just came on in the last 2 or 3 days. So we're testing that. So a combination of all that. We should definitely see a bump, at least 1,000, maybe higher, of net production.

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

Okay. Got you. In terms of the Atoka, you guys talked about deepening the wells. I think you were saying about $500,000 to $750,000 additional cost for roughly a 500-foot deepening. That kind of sounded a little bit pricey to me. Can you kind of walk us through the cost there? Is that all pretty much frac? Or how are you getting into that cost?

Timothy L. Dove

One thing we need -- you might have mentioned -- or you might have seen in the slide there, Leo, is we do need an intermediate string of casing because of the depth of those wells. By adding basically what amounts to 700 feet below the Wolfcamp, we're sort of at the limits of our traditional casing design. So we have to add our intermediate string, and that's really principally where the extra cost comes from. These wells are being drilled down roughly to 12,000 feet, so they're deeper than your traditional Permian, Spraberry drilling.

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

Got you. Okay, makes sense there. Just a question on your NGL pricing. You talked about sort of a 3% sequential increase in fourth quarter. I think, so some of the benchmark prices, like Mont Belvieu, were up a lot more significantly. Was there anything sort of going on there that sort of widened your differential at all in the first quarter, that you need to be concerned about going forward?

Richard P. Dealy

No, I don't think there's anything unusual by looking at it. It's just normal stuff, so nothing unusual jumps out.

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

Okay. Got you. Last question for you guys on the Waterflood in the Spraberry. Just curious as to how that's performing relative to the internal model at this point in time? And can you remind us how long you guys have been injecting water out there?

Timothy L. Dove

We started injecting -- I think it was in August last summer, Leo. And this is about the amount of time it takes as projected at that time, 9 months or so, before we start seeing some significant impact. We've already started to see production impact on individual wells. Remember, there's 100, 110 wells that are producing in that field. And so we've seen -- a select number of wells we've seen pretty significant increases and bumps to production. Importantly, we haven't seen any significant watering out events that would give us concern. And so overall, it's going exceedingly well and we're very positive on it. But it just takes time just for the whole system to basically fill up with water, which is what we're doing in the sense of this type of a waterflood. And so it's going well. We need a little more time to see. Ultimately, we expect the field to increase production from the one zone that's being flooded, which is the upper Spraberry.

Operator

And our next question will come from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

On the Wolfcamp shale horizontal well, with only 30% of the frac water unloading, can you set into context what you would expect going forward? And would you expect a materially higher oil rate, or should we expect that any additional hydrocarbons coming out of the well from here to get to what would be a normal apples-to-apples IP will be more liquids-rich natural gas? And can you kind of put where you are in this well in context with other wells drilled this early on, or completed this early on?

Scott D. Sheffield

Yes. Brian, first of all, this is the first well drilled in the entire Permian Basin in this zone, so we have no other data. Secondly, our well is flowing. We are not using jet pumps, as we could have used a jet pump and probably recovered the load water faster and got a much higher rate like some operators do, but this is just natural flowing. And so the gas-salt ratio is about 1,500 to 2,000 right now. And so we're encouraged by the fact that it's very, very strong pressure, flowing pressure at the surface. And getting only 30%, we end up using over 100,000 barrels, and so getting 30% back in probably roughly 2 weeks, less than 2 weeks, is very encouraging. We tested this zone vertically over the last 2 years and, essentially, got 5 to 10 barrels a day out of this zone, initial rate. And that's why we're opening this zone on all of our Spraberry wells now over the last 2 years. By getting 150 this early, it's semi-encouraging, but we're going to need rates much higher to pay out a $6 million or a $5 million well cost. So but we're encouraged by it. We're going to drill several more. And in addition, the Tippet shale, we are encouraged by what we're seeing there. There is a couple, 2 of the EOG wells out of about 8, that I've seen production data on, have come in about anywhere from 400 to 500 barrels a day. But say, the -- and that's why we're going to try tip it down towards the south, where we have probably 100,000, 150,000 acres, potentially, to see what that does too.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great, thank you. And then secondly, in your comments, you mentioned white sand proppant being used in the shallow Eagle Ford. Can you talk a little more specifically about cost savings potential there and how widely used that could become? Or if that's just something that's very niche for the small portion of your acreage and shallower pieces?

Timothy L. Dove

Yes. Brian, of course, as I mentioned, most of the acreage we're talking about is in the northwest part of the basin, or at least as it relates to our acreage, where it's a little bit shallower. And therefore, with the less depth, we have less pressures. And accordingly, sand becomes an alternative that makes sense. In fact, the offset operators in the northwest are using sand, and with give success. And so what we're already seeing is some pretty substantial positive results. What it will save for us is about 60% on the cost of proppant. And as you know, proppant in these wells can be well over $1 million. So I think we're looking at a savings that could be in the neighborhood of $600,000 to $800,000 per well. And to the extent it works, we think it could work on 20% to 25% of the acreage. We'll obviously be pushing that to see how much further we can move it to the south and east on our acreage as we get deeper because of that substantial savings.

Operator

And with Bank of America Merrill Lynch, Gil Yang has our next question.

Gil Yang - BofA Merrill Lynch, Research Division

If I could just follow-up on Brian's question a bit. So you're using ceramic proppant on the other -- essentially, all your wells right now. Do you see a need, a definitive need for the ceramic proppant at this point? Or is it possible that your expectation of the white sand on 20%, 25% is actually conservative?

Timothy L. Dove

Well, I should put it this way. We're going to be marching to the south and east with white sand, and see how far it works before we feel like we're going to have any degradation of results. One of the issues you face is the results only come at you slowly. It's hard to tell exactly, in the short period of time that we've been doing it, what the longer-term effects would be. So I think we're going to use caution and make sure we don't go too far, considering we're getting down -- as we go into our south and east, we're getting into 14,000-foot wells and very high pressure. So we have to be careful with it, but we're going to be pushing the edge of the envelope.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Fair enough. The flow-back on the second horizontal well, is it too simplistic to just say that as you recover more of the load water at the 1,150 barrels per day of total fluid recovery becomes more, is that it stays at 1,150 but it becomes oilier? And/or is it more likely that the water cut drops off, but the oil component stays more constant?

Scott D. Sheffield

Yes, we're hoping, obviously. We've had some rate up higher than the -- on a per-hourly basis than 150 barrels a day. And we've seen that come up over the last 2 or 3 days. So we're encouraged by that. So as we recover more load, we think the oil rate should continue to come up. And so that's what we think should happen.

Gil Yang - BofA Merrill Lynch, Research Division

And but typically, does the total rate drop off, and then the oil rate come up? Or does...

Scott D. Sheffield

Yes. The total rate will come down because you're getting more and more of your load. Eventually, you're going to leave a lot of your load back in, like we do in the Barnett and the Eagle Ford play. So in these shale plays, you're going to leave a lot of load water in the formation, which we didn't know how much in this one zone in the Wolfcamp.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And the hydrocarbons become a greater proportion of the overall flow back?

Scott D. Sheffield

That's right.

Gil Yang - BofA Merrill Lynch, Research Division

All right. Okay. In the carbonate horizontal, was there any particular reason that the frac went out of zone, as you can tell?

Scott D. Sheffield

Yes. We did not cement our liner work in place. And so we basically -- most of the frac went near the wellbore. And so we did not get the frac, essentially, effectively stimulated out in the horizontal.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And so but you didn't cement it by plan?

Scott D. Sheffield

We cemented the liner in the second well, the shale well. And that essentially allowed us to get an effective stimulation into all the various zones.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Does that tell you something about the azimuth of the well, as well?

Scott D. Sheffield

I don't know, Gil.

Gil Yang - BofA Merrill Lynch, Research Division

All right. And then finally, in the Barnett, the last 3 wells you said look like they had pretty good rates. Have you -- presumably, those last 3 wells are better than the first 2 wells. Have you learned how to do things better there? And from a methodology perspective, do you think the wells can be better going forward?

Timothy L. Dove

I think, Gil, as is the case in anything, that with the new projects, we're trying some new ideas in terms of how to stimulate the wells. And I think we've now done a better job of doing that. We had some issues on that in one of the -- the first couple of wells. And so I would think these last 3 are more representative, based on the learnings we've had.

Operator

And we'll now hear from Michael Hall of Wells Fargo.

Michael A. Hall

You mentioned that you had some kind of comparable results, I guess, in DeWitt County relative to the Black Hawk field results. Can you give any color or any sort of statistics on recent wells in that area?

Scott D. Sheffield

No. I think our main point is that we have a type curve of -- we keep detailed production data on those type curves. And in that area, they're way exceeding our type curve on the rich condensate, just like Petrohawk has stated. Our average -- we're staying with our overall average of 6 BCF equivalent. That includes dry gas, lean and rich condensate. But we're just stating them in that high-liquids area in DeWitt County, that all of our wells there exceeding our type curve.

Michael A. Hall

Got you. And then, I guess just moving quickly into the Permian. As you move deeper and you continue with the deepening program, remind me, does the mix, the hydrocarbon mix, change meaningfully from interval to interval?

Scott D. Sheffield

No. Pretty similar gas-oil ratio. So liquids is still going to be 90% in the Strawn and the Atoka based on our Strawn wells and other operators' Atoka wells.

Operator

And we'll now hear from Joe Allman of JPMorgan.

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

Just a follow-up on the Wolfcamp horizontal. I know you touched on this 2 questions ago, but about how much of the frac load water do you expect to get back? Is it somewhere in the neighborhood of 50%? Or could be as high as 75% or more?

Scott D. Sheffield

It's a guess, Joe. But the way it's going, it could be 50% or plus.

Richard P. Dealy

50% to 70% in the Barnett.

Richard P. Dealy

Yes. In the Barnett, we get 50% to 70% back, to give you an idea. Eagle Ford is 10% to 15% because of the higher pressures. It essentially evaporates down there.

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

Okay, that's helpful. And then in terms of the natural gas that you're starting to see. Are you seeing liquids-rich natural gas?

Richard P. Dealy

I have not seen a test, but it should be. 1,500 gas-oil ratio is about what the gas-oil ratio is in a typical well at Midland, Martin County and all the zones, starting at about 1,500 gas-oil ratio. So I'm pretty -- I would be pretty certain that it's 1,400-Btu gas.

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

Okay, that's helpful. And then in terms of this, the potential for the Wolfcamp horizontal. As you got these different intervals that you identified in your presentation. Are those intervals present throughout your acreage?

Richard P. Dealy

Essentially, yes. It looks better than certain areas. Like in, for instance, the Martin, Midland County is better, we think, for the lower Wolfcamp. The Tippet is better, it looked, based on log data only, in the southern part of our acreage. So but we do have those zones throughout the entire Spraberry Trend area.

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

Okay. And then in terms of your development or your testing of this play, are you staying in a geographic area and just trying to test the different intervals in a certain area? Or are you kind of spreading out throughout your acreage and testing various intervals?

Richard P. Dealy

We're going to spread it out. I mean, the wells to the south will be -- I mean, we'll drill some wells up north, they'll probably 100 miles apart. So these next 6 to 8 wells, and we'll probably drill another 5, 6, and going into '12 we'll complete our program. They'll be 30, 40, 50, 60 miles apart, as much as 100 miles apart.

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

That's helpful. And then if this play works, presumably, you'd have to alter your vertical drilling, because I imagine if this -- if the horizontal is more economic, you would focus on the horizontals in the Wolfcamp. But then I'm not -- how would you work out the vertical program at that point?

Richard P. Dealy

Most likely, we will continue our vertical program and drill a series of horizontals. And so we'll have to work with the commission in Texas that regulates oil and gas in regard to how much acreage is dedicated to each. But we don't see a slowdown at all in our vertical program. And the horizontal, if we start one, it'll just be an acceleration on top.

Operator

And our next question will come from Richard Tullis of Capital One Southcoast.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Scott, you had mentioned the well cost for the Wolfcamp horizontals. I guess it was $5.5 million, $6 million. Now those are the first 2 wells? Or is it more of a...

Scott D. Sheffield

That's right.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. So at development mode, it would be less than that?

Scott D. Sheffield

Yes, it would. And also, using -- depending if we use our own, any of our own rigs and our own frac fleets for that, it would have some savings also.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. Just for a reference point, what's the typical IP for a Spraberry vertical?

Scott D. Sheffield

Ignoring just Spraberry Wolfcamp, they're coming in about 80 barrels a day now. They used to come in about 50 barrels a day, with just Spraberry Dean. They're up in the, on average, 80 barrels a day, Wolfcamp. Some of the Strawn wells, we're seeing, we open up the Strawn, get close to 100.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. That's helpful, thank you. When do you expect the next update on the horizontal program? When will you spud the third well?

Scott D. Sheffield

We're not going to start our program until the third quarter. And so we'll dedicate one rig to the program and drill the series of 6 to 8 wells and probably add. It will continue, I'm guessing, into the second quarter of 2012. We want to put 3 to 4 in each of these R&D projects, in each of these 4 zones. So there'll be 3 -- at the end of the day, we'll have 12 to 16 wells total, covering 4 different zones. It'll take us a good year. But so -- we'll release data as we get it.

Richard M. Tullis - Capital One Southcoast, Inc., Research Division

Okay. That's helpful, thank you. And as you're coming across more and more potential zones to access with vertical wells in the Permian, what's your outlook, currently, on potentially monetize and JV or outright sale of some of your acreage position in the Permian?

Scott D. Sheffield

It'll take us a minimum of 2 years to understand the deep rights, the deep potential of the Strawn, Atoka. And even, there's deeper zones that our geologic team is studying below the Atoka. And then the horizontal program will be completed probably, roughly, in about a year. And we'll need a good 6 months production. So we're 2 years away from even thinking about JV-ing at that point in time, whether or not to accelerate any of our activity even further at that point in time.

Operator

And we'll move on to John Nelson of Macquarie Capital.

John C. Nelson - Macquarie Research

Just wanted to talk about the Spraberry. With 7 frac crews at year end, I was wondering what you think your quarterly well completion capacity in the play will be? Just looking at the slides, it looks like you expect to add 225 wells a quarter, sort of towards the end of the year. I'm just wondering how far above or below -- or how far above, with 7 frac crews, you might be able to go from there?

Timothy L. Dove

John, first of all, what's reflected in that draft is dedicated crews. And that doesn't -- all that is to say that we also have spot crews working. But to give you a frame of reference, in the early stages, as we put our frac crews in place, they average about 10 wells, a little over 10 wells per month. We're actually going to be going on 24-hour operations on our crews. We're seeing improved efficiencies through time. And so our objective is to get maybe in the neighborhood of 12 to 13 wells done per month. And so if you do the math, that means that each frac fleet can do 150, 160 wells per year. So it can get where -- that means that with 7 crews working, we're upwards of 1,000 wells. So we'll be relatively self-sufficient, even at the 1,000-well campaign going into next year.

John C. Nelson - Macquarie Research

Great. And then just one question on the Eagle Ford, trying to -- to your comments about wells in DeWitt County perhaps coming in higher than your previous guidance. Is that potentially why you have more confidence in sort of the 2011 production guidance? And despite having some problems getting frac crews there now, you guys still sort of maintain that number?

Timothy L. Dove

Well, I think really it really doesn't have much to do with DeWitt County wells as much as it is our overall program. And we've got, as you can see, quite an amount of definition, quite an amount of granularity surrounding the frac schedule, the frac crews. What we don't show you on there is that there are several spot crews, as I mentioned in an earlier question, that we'll be utilizing on and off, especially in the second quarter. And so, it really is more of the execution on our current plan that's yielding the production results that are showing on the Eagle Ford graph.

John C. Nelson - Macquarie Research

Great. Do you guys have an expectation for what your year-end rate in the Eagle Ford will be?

Scott D. Sheffield

It's pretty much set out. You can pretty much look at the second half production in the slide and look at the number of wells that are being completed. So...

Operator

And with Canaccord, we'll hear next from Marcus Howard.

Marcus Talbert - Canaccord Genuity, Research Division

Most of my questions have been answered, but I did want to double back to the horizontal program you mentioned with the one rig running and the wide area that you'll be testing in for the different intervals. Is it just the amount of time taken, getting the rig across these 50, 60 miles? Or is that what's causing sort of the time to test the full program for the year, is there no reason it couldn't be accelerated further?

Scott D. Sheffield

We can accelerate it, obviously, with more rigs. But to me, I think, the markets got -- as I stated earlier, the markets got way ahead of the horizontal program. I mean, when you're getting 50%-type returns on 700 wells, 1,000 wells on our vertical program, it's going to have to take tremendous results to get to 50%-plus returns on the horizontal side. We just feel like, since we have 40 billion to 50 billion barrels of oil in place in this field, that it's important to test all these zones over the next 12 months. So we're just not going to -- we're going to take our time about it. We're not trying to hype it as other companies are. And it's an R&D project. And so we could run 4 rigs if we wanted to, but we're just going to dedicate one rig. And we want to make sure we don't take away from our vertical program. If we run 4 rigs, we'd have to take away from our vertical program. And most of our production's held by production. So we just want to do it methodically, carefully. And so that's why we're just dedicating one rig to the program, which will take about a year to finish a program.

Marcus Talbert - Canaccord Genuity, Research Division

Understood. Really appreciate that color. And with these big numbers that you're talking about with the vertical program. Understanding that, just planning on drilling the 10 to 20 Atoka wells this year, is there any horizon beyond the Atoka that might be prospective for a test this year?

Richard P. Dealy

Not for a test this year, but we're definitely studying the next 1,000 feet below the Atoka.

Operator

And we'll hear next from Dan Morrison of Global Hunter.

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

A couple of quick questions. One, what are the wells...

[Technical Difficulty]

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

What are the well counts associated with your current outlook in the Spraberry and the Eagle Ford for '11 and '12?

Scott D. Sheffield

Tim, do you have the exact number?

Timothy L. Dove

Let's see. 2011, let's use still Permian first. Permian has 700 wells in 2011, right at 1,000 wells 2012. Eagle Ford, we had approximately 100 wells we're drilling in 2011. The current plan for 2012 is not finalized but we're saying, essentially, it's approximately 130 to 140 wells.

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

Okay, thanks. And the Strawn potential, you mentioned, at 40%. Where does that kind of lay out geographically? Either counties or directions, or is it concentrated, or does it vary around a bit?

Scott D. Sheffield

Yes. It's primarily Midland and Martin County.

Richard P. Dealy

And same with the Atoka.

Scott D. Sheffield

It's going to be Midland and Martin.

Timothy L. Dove

When you look at acreage, Matt, that's principally in the central part of our acreage holdings.

Operator

And we'll move on to Brian Lively of Tudor, Pickering & Holt.

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

Just thinking about the vertical test that you've had in the Wolfcamp before going horizontal. What are the water cuts on those vertical wells?

Scott D. Sheffield

The vertical on a typical Spraberry well?

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

Well, I just meant on the specific test, you said you got 5 to 10 barrels a day of uplift just testing the Wolfcamp before going into the horizontal program. I was just wondering...

Scott D. Sheffield

[indiscernible] it's less than 1:1.

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

Okay. So it's not going to be like a typical full Spraberry completion where you see kind of the 60% to 70% water cut, you're expecting much lower water cuts? [indiscernible]

Scott D. Sheffield

Yes. We're getting most of that water out of the Spraberry out of the upper Spraberry. The upper Spraberry seems to be a lot higher water saturation throughout the entire field, but it does have full lots of oil. So that's what's pushing the water rate up into -- total water in our -- the typical Spraberry well.

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

And so you said potentially 1:1, does that mean a 50% water cut? Is that what you're thinking?

Scott D. Sheffield

1:1 is 100%, I mean, so it's equal to 1:1.

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

Just, so you're seeing oil equal water, is what you're saying?

Scott D. Sheffield

Yes, exactly.

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

Okay. I just wanted to make sure I understood. And then just on the Eagle Ford, and I'm sorry if I missed this, but what's your current backlog of uncompleted wells there?

Timothy L. Dove

Approximately 15.

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

15. And you think you can work those down pretty fast now?

Timothy L. Dove

Yes. We're working them down as we speak. And in fact, it was a higher than that only a month ago. But the fact is we brought in these 2 frac fleets, one of which is a Pioneer-owned fleet, and we are very effectively working down our frac bank as we speak. Should be no more than about 10 wells at the end of the year, for instance.

Operator

And our next question comes from Eliecer Palacios with Maxim Group.

Eliecer Palacios - Maxim Group

Just a quick question on your Alaska property. Could you provide just a quick update on your potential exploration there? And when can we hear results of your current well?

Scott D. Sheffield

Yes, we've already -- I did bring up already that our second Torok well came on just in the last 2 days, about 900 barrels a day. Testing it over the next several weeks. And then we're -- we just finished a recompletion program on several wells, so we expect an uplift in our production. And then over the next -- we're preparing for, again, our winter program. And we'll be drilling, again, several more Torok wells going over the next 2 or 3 years. We'll be drilling a key well onshore in the Torok this coming winter. And in addition, we'll be testing a deeper exploration zone that we've evaluated. The Torok was the third zone when we approved this project, we only had 2 zones: the Nuigsut and the Kuparuk. We've had the Torok now. And we're looking at a fourth zone that's even deeper, and we'll be testing this in the upcoming winter.

Operator

And our final question will come from Michael McAllister of Sterne Agee.

[Technical Difficulty]

Operator

And there are no further questions at this time.

Scott D. Sheffield

Okay. Well, we appreciate all the interest during the quarter, and we look forward talking to everybody on the next quarter around the road. And hope everybody has a good summer coming up. Again, thanks.

Operator

And that does conclude today's teleconference. Thank you all for your participation.

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