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Pioneer Natural Resources (NYSE:PXD)

Q2 2012 Earnings Call

August 01, 2012 10:00 am ET

Executives

Frank E. Hopkins - Senior Vice President of Investor Relations

Scott D. Sheffield - Chairman and Chief Executive Officer

Timothy L. Dove - President and Chief Operating Officer

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

Analysts

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

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Will Green - Stephens Inc., Research Division

John C. Nelson - Macquarie Research

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

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C.

Sven Del Pozzo - IHS Herold, Inc

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Abhishek Sinha - BofA Merrill Lynch, Research Division

Operator

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

Pioneer has prepared PowerPoint slides to supplement their comments today. These slides can be accessed over the Internet at www.pxd.com. Again, the Internet site to access the slides related to today's call is www.pxd.com. At the website, select Investors, then select Investor Presentations. This call is being recorded. A replay of the call will be archived on the Internet site through August 22.

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 states and the business prospects of Pioneer are subject to a number 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 findings (sic) [filings] made with the Securities and Exchange Commission.

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

Frank E. Hopkins

Good day, everyone, and thank you for joining us. I'm going to briefly go over the agenda for today's call. Scott is going to be up first. He will provide the financial and operating highlights for the second quarter of 2012. He'll then discuss the company's plan to pursue a joint venture partner to accelerate the development of Pioneer's industry-leading position in the horizontal Wolfcamp Shale. He'll also update you on our increased production growth forecast for 2012, and capital spending plans over the remainder of the year. After that, Tim will be up. He'll discuss our drilling results and plans for the horizontal Wolfcamp Shale, Spraberry vertical wells, the Eagle Ford Shale and the Barnett Shale Combo play. He'll also update you on our activities in Alaska. Rich will then cover the second quarter financials in more detail and provide earnings guidance for the third quarter. And then after that, we'll open up the call for your questions.

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

Scott D. Sheffield

Nice, Frank, and good morning. On Slide #3 in our highlights, we had a clean adjusted income number of $98 million or $0.78 per adjusted share. Second quarter production, which we had already press released a couple of weeks ago, totaled over 150,000 barrels of oil equivalent per day. The Spraberry production was negatively impacted by about 4,800 barrels of oil equivalent per day due to unplanned third-party NGL fractionation capacity shortfalls at Mont Belvieu. Did include 2,800 barrels a day associated with NGL inventory build, which we do expect to sell between now and the end of the year, and 2,000 barrels a day from ethane rejection that will continue. Production would've been about 155,000 barrels a day without the negative impact, which have been at the high end or above our guidance of 149,000 to 154,000 barrels a day. We were up 4,000 barrels a day versus the first quarter, primarily driven by the production growth in Spraberry, Eagle Ford, Barnett and Alaska. One note is that all production is up 70% over the last 12 months with Pioneer.

Increasing 2012 production growth, our target range, which was 23 to 27, up to 25 to 29, as strong drilling and well performance is expected to outweigh the continued third-party NGL fractionation capacity shortfalls and our reduced second half drilling activity. Between -- to advance the successful Horizontal Wolfcamp Shale plays, we're announcing 5 additional wells, very successful, for a total of 7. The program is way exceeding expectations. Increasing our estimated ultimate recovery to 575,000 barrels oil equivalent for 7,000-foot laterals in our southern acreage. Also, we're announcing, of the next several months, we're pursuing a joint -- looking for a joint venture partner to accelerate horizontal Wolfcamp Shale development in our southern 200,000 acres of our total perspective acreage position. We'll talk more about that in a minute.

Going to Slide #4. Continued on highlights. Our deeper vertical drilling to the Strawn, Atoka and Mississippian continue to drive the strong Spraberry performance -- out-performance in that field. Also, what's important, maintaining our drilling capital at $2.4 billion by reducing second half activity in response to the recent -- in the last 60 days, the price of WTI coming down from roughly $100 to between $85 and $90 from lower commodity prices.

We're taking the Spraberry rig count down a little bit quicker than we anticipated in this price environment, from 40 to 30, reducing the Barnett rig count from 2 to 1. Also, we're looking at reducing the Spraberry vertical rig count from 1 to 3 rigs. In addition, we have terminated some third-party fracture stimulation fleets and are now predominantly using Pioneer fracture stimulation fleets, saving lots of capital there. We liquidated some gas derivatives, in 2014 and '15, several weeks ago. And the market obviously has moved up since then, substantially, with cash proceeds of about $143 million. And also recently when oil peaked at about $93 just recently, we went ahead and added 8,000 barrels a day of oil swaps for the next -- for the last 5 months of 2012, which puts us close to 100% of our oil hedge for the rest of this year.

We completed a successful tenure senior note offering of $600 million at 3.95%, and with the S&P upgrade, we've recently been upgraded by Moody's.

The Wolfcamp Shale joint venture opportunity on Slide #5. With the data room opening up in September, we're offering 1/3 to 50% of Pioneer's working interest in approximately 200,000 acres in the southern portion of the Midland Basin, which is about 8% to 12% of our total acreage position, when you look at a partner obtaining either 1/3 or 50% of our 200,000 acres. It's going to include all Wolfcamp intervals, A, B, C and D. There's 4,000 potential horizontal development locations, excluding down-spacing potential. Our 4,000 locations, we are drilling now on 140-acre spacing as you see with activity like in Eagle Ford oil where people are taking that play down to 53-acre spacing. So it's huge potential over and above the 4,000, and over above the 2-billion-barrel gross resource potential. The 2 billion barrels are just associated with the 4,000 locations.

Oil content, greater than 70%, with liquids greater than 90%. Estimated ultimate recovery, in this acreage, about 575,000 barrels of oil equipment for a 7,000 foot lateral. Been a current environment of $85 oil flat and $4 gas flat, $7 million well cost delivers a 45% before tax IRR.

The primary purpose of the shale JV opportunity is to accelerate development, enhances our net asset value and project returns, allows us to de-risk the play with somebody else's capital. And that also allows us to shift capital to Midland, Martin, and our counties to the North, to prove-up additional Wolfcamp where we own essentially about 100%.

Going to Slide #6. Increasing our 2012 production growth target. Again, as had I mentioned before, we're going from 23% to 27%, up from 25% to 29%. Obviously, our strong drilling, in all of our key areas, is outweighing what's happened on the NGL fractionation at Mont Belvieu. Again, going into 2, 3 years, beyond 2012, we'll wait until early 2013 to come out with that guidance. But, again, that's very dependent upon commodity prices and service cost going forward.

Capital spending for the second half of the year and cash flow on Slide #7. As I had mentioned earlier, we kept our drilling capital at $2.4 billion by reducing certain areas in activity. Vertical integration, $500 million. We did add about $100 million for expanding field facilities, primarily in the Permian Basin, Eagle Ford, that'll carry us for several years with our accelerated activity over the next several years in those 2 key areas, for a total of $2.9 million. Funded from operating cash flow, equity proceeds, liquidated derivatives and inventory -- pipe inventory reduction, South Africa divestiture and South Texas acreage sale.

Going to Slide #8. Again, another slide to emphasize the fact that the first half capital spending was weighted toward the first half due to a second rig drilling in Alaska, which drilled 2 exploration wells, which we owned 100% of each of those wells. Running 40 Sprayberry rigs in the first half, going to 30 the second half. We did accelerate our frac bank reduction of 40 wells, so a lot more completion cost in the first half. A lot of capital, we're spending about $2 million extra for science in the first half, on horizontal Wolfcamp wells and then Seismic acquisition, primarily in the Permian.

I'm going to the second half, we'll be running somewhere between 27 and 30 Spraberry vertical rigs, 4 horizontal rigs until the very end of the year, where we'll be adding 3 more rigs ourselves, regardless of what happens on the joint venture. The joint venture does go through, obviously, we'll be running more rigs going into 2013 and '14.

12 Eagle Ford rigs, 1 Barnett Shale Combo rig, 1 Alaska rig, and again, predominantly using our own frac fleets, the second half of the year.

And finally, on Slide #9. South Africa should be closing in the next couple of weeks. We're predominantly a U.S. asset-based company. We have increased our resource potential up to 7 billion barrels of oil equivalent. We think there's additional upside from this number. This has increased primarily with the Southern Wolfcamp acreage play. As we move into Midland and Martin County, we think there's tremendous upside to that number as we expand the Wolfcamp play up north. Again, we've got 4 great core areas. The joint venture is going to, obviously, accelerate the development of the Wolfcamp Shale play. Vertical integration substantially improves returns, we have a great derivative position that protects margins over the next 2 years, and a strong investment grade financial position.

Let me stop there and turn it over to Tim to go more into the Wolfcamp.

Timothy L. Dove

Thanks, Scott. We're pleased to finally be able to report our drilling results from the early campaign in the southern 200,000 acres that Scott was referring to in the Horizontal Wolfcamp Shale play. In summary, the early results from the program are exceeding our expectations. But, first, let me do this, let me update you on the Giddings wells in Upton County. Those were the first 2 horizontal wells drilled several months ago to the north. And as shown on the slide, we've had phenomenal results from these wells. The first of which has made 107,000 BOE in about 9.5 months. The second of which made 83,000 BOE in 7 months. Again, this is roughly about 7x the amount of volume that would -- a typical 140,000-barrel type curve from vertical wells would make. And I'll refresh your memory that these wells actually naturally float up tubing until only about 1.5 months ago. So now, only in the last 1.5 months have we put the wells on artificial lift. You'll see in the box to the right that we have a conservative 650,000 BOE -- EUR for these wells. Realizing their stimulated lateral lengths are only 5,300 feet. As we increased the length of those laterals you'll see the EUR to the north grow considerably. And the important thing about the wells is they are still exceeding expectations. Even in terms of current production, they're averaging about 365 BOE per day, which is, again, a phenomenal result for these first 2 wells and is indicative of what we expect as we go north onto our acreage.

Now, let's turn to the south. As Scott mentioned, plays 5 B interval wells on production during the quarter, mostly there in Southern Upton and Reagan Counties, as the map shows. And the actual data for these wells, all 5 of them, detailed or shown in the table below. Importantly, the wells have done exceptionally well, 300 to 600 BOE per day, in terms of peak 30-day IP rates. Of course, we think that peak -- the 30-day peak rate is really more indicative of performance than the 24-hour rate. And importantly, a lot of these wells are really doing phenomenally in terms of showing stabilized production. In fact, the total of the 5 wells, on average, they're still producing over 300 barrels a day over the last 7 days. So it goes to show the wells are holding up beautifully. And the last of the wells, as shown on the table, University 10-13, is -- still, today, naturally flowing up casing and showing excellent rates as shown on the table. And so we're actually considering completing all of the wells perhaps in the future in this fashion, so as to be able to move fluids faster. And as you can see we're continuing to really refine the optimal completion techniques on these wells, and I think you'll see improvement as we go forward, based on all the technology we're applying. And importantly, as we move ahead, I think the production rates and EURs will also increase in relation to the increase in stimulated lateral lengths. The numbers we quote today, on EURs, are based on 7,000-foot laterals. We'll be looking at drilling some 9,000-foot laterals in the second half of the year. And as Scott mentioned, just based on 7,000-foot laterals, we've increased the EURs in the southern area, to about 575,000 BOE. You'll recall, our range, prior to having this data, was more in the range of 350,000 BOE to 500,000 BOE. So the results look very, very good in the early stages of our drilling campaign.

Turning now to Slide 11. This slide is focusing on the future activity in the horizontal Wolfcamp Shale play, the rest of this year and into next year. Of course, our activity, as shown on the map, in the oval there, is related to trying to hold the 50,000 acres that would otherwise expire at the end of 2013. And toward that end, we have to drill about 90 wells or so, between 2012 and '13, to hold that acreage. So, today, we have 4 rigs running. We'll be increasing that to 7 rigs in the late part of the year. Those rigs are all contracted today. There are 9 wells that have been drilled, they are awaiting completion, they're waiting on fracs. And importantly, 2 of those wells are first Wolfcamp A test. In fact, the first frac -- the first well being frac-ed began on Monday. The second will be done in midmonth. And so, accordingly, by the time the next call occurs, we should have a lot of interesting data on Wolfcamp A as well.

The important note regarding drilling cost is that we are trying to move to more of a development drilling campaign. Of course, we've been spending a lot of money on the early wells for science and data. But we're drilling our first 2 development wells, focusing on trying to get the well cost in that range of about $7 million. I think we can do that. One of the changes that we're in the process of implementing is increasing utilization of our Brady Brown sand from Premier Silica. That's our sand company. Today, we pump about 50% white sand, 50% resin-coated sand. Our goal, as we move forward, is to move to about 85% Brady Brown sand, and that can save us $1 million per well. So this is an important thing to be testing immediately, and that's exactly what we're doing.

As Scott had mentioned earlier, we also -- we'll be marching forward in delineating the northern acreage, drilling some wells in Midland and Martin and Gaines counties, as we get on the latter part of the year. We anticipate higher oil in plays there, deeper drilling, higher pressures and we think, as a result, more productivity going north. And of course, that will help us be able to establish the prospectivity of our acreage in terms of the total acreage package.

Recently, our team of Permian engineers did a great job in working with the Railroad Commission of Texas to adopt new field rules. It's the objective is to optimally develop the vertical and horizontal Spraberry sections. Ultimately, this will allow a development which would feature up to, perhaps more, even than 14 horizontal wells in the Wolfcamp on a section and a half, which could be coupled with as many as 41 offsetting 20-acre space verticals. And so you're looking at a field rule change that will really significantly improve recoveries and we believe will optimally develop the field.

So as you can see, we're just in the beginning in unlocking the immense value of the Horizontal Wolfcamp Acreage, and in our prospective acreage in the play. So stay tuned as we start the process of completing the rest of these wells and drill further wells.

On Slide 12, I'm now turning to, plays, the vertical deepening program, as well as the horizontal Wolfcamp shale program that's going. It's still the vertical drilling programs, specifically the deepening of wells, which has allowed us to exceed our growth targets through the first half of this year. And in fact, at this point, we are deepening about 65% of the vertical program. We had planned, this year, to be deepening only about 50%. But as good as the results have been, we're increasing the program to about 2/3 of our campaign. The table here on Slide 12 shows 24-hour IP rates or the deepened wells, whether it be the Strawn, the Atoka or the Mississippian. And you can see, these compare very favorably when you consider that the 140,000 barrel type curve, associated with normal vertical Wolfcamp completed wells, has an IP of about 90,000 BOE per day. So you can see the impact which, I think, deepening is having in the early stages of well performance. And the table also shows the potential incremental EUR from the deepenings. Importantly, we've done some work, some further analysis, in refining of our mapping to assess the prospectivity from the deeper zones. We now believe the strong prospectivity is towards the top end of our prior range. We had used 60% to 70%, we now believe it's about 70% of the acreage. Atoka is coming in at the top end of its previous range of 25% to 50%. We now believe it's in the neighborhood of 40% to 50%, and Mississippian continues to be prospective for about 20% of the acreage. And so, the deepening really has been a excellent result for us. It's the thing that's leading us to outperform in this play. And it's the case that we can, I think, add significant EUR perhaps even up to 100,000 BOE per well, when these deep zones are co-mingled.

So, then, turning to Slide 13. This, really, is a slide which shows the effect of the successful drilling campaign and the effect of the well deepenings I just covered. You can see, we came in at 64,000 BOE a day for the quarter. That would've been 68,500 BOE a day for the quarter, other than for the well-documented NGL issues that Scott has already covered. That has led us to the increase forecast for this year's production for the Spraberry trend area, to 63,000 to 67,000 BOE per day, and that underpins the increase in the overall corporate production guidance that Scott has already covered. And we really anticipate that, although we're going to be in a situation in which we have ethane rejections through the rest this year, we think it'll be a very strong finish to the year. Permian asset base is delivering in a major way, and a lot of the production of course is due to the well deepenings.

Now turning to Eagle Ford on Slide 14. This is an asset base that continues to grow and will continue to do so. We put 37 wells on production during the quarter. We continue to have 12 rigs running and still anticipate a 125-well campaign. We have reduced, slightly, the number of dry gas wells we plan to drill, from about 15% of the program. Now it looks like we'll only drill about 10% of the program or about 12 wells, focused on holding dry gas acreage, in response to commodity prices. We continue to expand the limits of the utilization of white sand. Of course, we were using white sand in several wells already this year, 53 wells have been stimulated using white sand. Importantly, we're just using white sand for the first time, on some dry gas drilling, in order to try to cut the cost on dry gas wells, and have 4 more of those wells planned for the remainder of this year. And importantly, that's a $700,000 savings per well, and that's why it's important to test it on what would otherwise be economically challenged dry gas wells.

We're a leader when it comes to having infrastructure in place. We have added 3 more CGPs in the second quarter. That gives us 11. We have 3 more to put in next year and that will have us substantially complete in terms of our infrastructure build-out at the end of 2013, for the Eagle Ford Shale play.

Turning to Slide 15. This shows the results of the activity and the growth from the Eagle Ford Shale. We expect that growth to increase in the second half of the year and you can see that in the overall fiscal year, our full-year guidance. We're going to be putting more wells on production in the second half than we did in the first. We popped 63 wells in the first half of this year and anticipate putting 76 wells on production in the second half of the year. And that underpins the production increase in the second half of the year.

Turning to Slide 16, our third major area of Texas-based drilling is in the Barnett Shale Combo play. We drilled 12 wells in the second quarter. We did announce, as Scott mentioned, reducing our rig count by 1, from 2 rigs to 1 rig. This is in response to a combination of relatively low natural gas prices as well as the decline in NGL prices that was pretty substantial in the second quarter. We have seen some drilling results that have been very encouraging. In fact, they've been oily well results which, of course, is beneficial in today's commodity price environment. In fact, we drilled 7 recent wells that had 30-day peak rates of 345 BOE per day and we're more oily than the typical Barnett shale well. Importantly, we are still incrementally adding value by gaining substantial efficiencies in drilling. We moved our drilling times, on these Barnett Shale wells, down from about 16 days last year to about 10 days currently, and that savings is significant.

In turn, as you turn to Slide 17, production continues to grow in the Barnett Shale Combo play. We're confident in the range for the year. Of course, the rate of growth will slow as we see towards the end of the year, as see the effects of reducing the rig count from 2 down to 1. We'll be looking at, and evaluating the 2013 capital for the Barnett Shale combo play in the later part of this year as we look at the outlook for NGL prices as well as natural gas prices through the rest of this year, and looking at the expectations for next year.

Slide 18, a quick update on Alaska. Production was up in the quarter, owing to the first successful Nuiqsut well had been mechanically diverted -- frac-ed earlier this year. And that well is on for most of the quarter. We do have the 1 rig running, still, on the island. And that rig, principally, is working on drilling wells that will be the subject of 4 additional diverted fracs for the next upcoming winter season. Of course those fracs will not be done until well after the freeze. We need space for the frac lead and we put the space for frac tanks and other equipment. So we're going to need ice for space around the island, so we really won't be getting to those fracs 'til probably February.

And in addition, we are doing some planning to drill perhaps another Torok appraisal well from the shore. The idea is offsetting the excellent well we drilled last winter and evaluating the potential for the development and, in fact, spending money on the upfront FEED study as we speak. We believe, as a result of the campaign last year, we've had about 50 million BO -- barrels of oil, in terms of resource potential, in the Torok area.

Our other, principally gas-producing areas in the mid-continent and Raton, and South Texas, performed very well in the quarter despite being allocated very little capital. And the slow decline on these assets gives us a great production foundation from which we can grow and that's attributed to the people in these divisions doing an excellent job.

With that I'm going to pass over to Rich for a review of the second quarter financials and his outlook for next quarter.

Richard P. Dealy

Thanks, Tim. I'm going to start on Slide 19. For the quarter, the company reported net loss attributable to common stockholders of $70 million or $0.57 per diluted share. That did include unrealized mark-to-market derivative gains of $61 million or $0.49 per diluted share, and unusual items representing net charges of $229 million or $1.84. So, adjusting for those items, most of which was noncash related to Barnett Shale impairment-related legacy dry gas properties, resulted in a $98 million, as Scott mentioned, of adjusted income or $0.78 per diluted share.

Looking at the bottom of Slide 19, production, Scott and Tim both discussed I'm not going to talk anymore about that. If you look at the other items here, relative to our second quarter guidance, they were either within guidance or at -- on the positive side of guidance. Another good quarter for the company.

Turning to Slide 20 and looking at price realizations. As Scott mentioned, we did put out, middle of July, our production and price realizations for the quarter. Here, as you can see, looking at oil, realized prices were down 12% from the first quarter, at $86.87. NGL prices were impacted pretty substantially due to lower ethane and propane prices, and they were down 22% from the first quarter, at $32.62 per barrel. And then, looking at gas, we're down 20% to $2 from $2.51 in the first quarter.

Turning to Slide 21. Production cost came in, for quarter, at $14.70 per BOE. That was a 7% increase from the first quarter. Couple of items that are enumerated here. Increased work-over activity during the quarter, just the timing of when that activity took place. We have seen some minimal cost inflation on labor and salt water disposal cost. That hit us in the second quarter as well. And then, it's small, there at the bottom of the pie -- or the bar, the net gas processing. Margins were down, we processed third-party gas through our facilities where we have excess capacity and we get paid, generally, for that with percentage of proceeds and with lower gas and NGL prices, that affected our margins. And then lastly, when you look at production cost on a BOE basis, the ethane rejection reduced our production or the denominator in the calculation, and so that impacted production cost by $0.19 per BOE for the quarter.

Turning to Slide 22. Third quarter guidance. Production guidance of 155,000 to 159,000 BOEs per day for the third quarter. That does reflect continued ethane rejection throughout the quarter. Our production cost at $13.50 to $15.50 per BOE. Exploration and abandonment $25 million to $40 million, and that's down slightly. It was just less exploration drilling activity, and seismic activity in the second half. And then the other items are consistent with previous guidance other than, interest expense reflects the bond offering that Scott talked about earlier. And then other expense reflects additional rig termination fees.

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

Question-and-Answer Session

Operator

[Operator Instructions] We'll go first to Brian Lively with Tudor, Pickering, Holt.

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

Yes. On the 5 Wolfcamp wells. It's just interesting that the University wells are all sort of completed in close proximity, but the IPs were different. And I understand there's some variability to be expected. But when you guys look geologically, is there any difference in terms of the lithology or the rock as you moved across that southern acreage position where you drilled?

Timothy L. Dove

No. We really don't see too much. There is a combination, I think, and Tim mentioned it. That you got 1 well on jet pump several on gas lift and we're learning that, flowing back the wells, up on the casing is probably the best process going forward. So that's why you get different variance of rates. And so, we're going, almost all of our the wells now, we're going to start flowing back for several weeks to months, to established low decline and get the best performance. So we just don't see much change to that. We think, as you move, maybe toward our Rocker B, we may get a little bit more gas. But, so far, our gas ratios are staying 1,000 or under, and even as we move south. Now as we move southeast, more toward EOG and approach, we anticipate maybe a little bit more gas and NGLs. We don't know that yet.

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

And on the University wells, the 4 50-ish IP wells that were put on artificial lift early. I think, Scott, you're saying that you might not do that in the future, and that could be the reason why the wells were lower rate than, say, some of the other offsets that are on natural swell?

Scott D. Sheffield

Yes, that's right. In fact, the best University well has been flowing back, and Tim mentioned it, and it's the process that we usually [indiscernible] also, and that's why it's got a higher 30-day rate, because we're flowing it back. So the goal is to flow it back up 5.5-inch casing versus -- the Giddings wells will actually flowed back. They were restricted. They were flowing back under tubing. So we think that the flow back is the best procedure right now and we're going to do that going forward for a while.

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

Matt, I guess that support the idea, that you'll see flatter declines on some of the wells, especially once you put on artificial lift on early?

Unknown Executive

Yes.

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

And then just on that, the overall acreage, is there any way that you guys could segment it, maybe between the 3 different areas? Sort of the southern, the mid and then the northern, that you've untested. Just kind of give some sense of what you guys think you've de-risked at this point.

Richard P. Dealy

To the north, as you recall, the only well we drilled to the north has been a Cline well in the D zone, in Midland County. In fact, that well has become very flat and it's getting and better. We only frac-ed -- it was only that well at a 3,800-foot lateral. And so, we're becoming, obviously, more optimistic in the Cline, through Midland and Martin County, but we're still going to be focusing on the A and B zone. But with the database of 70,000 logs and core data, our map show that -- been some of the other activity to the North and Davin had a pretty good in Ector County, just offset due west of Midland County. And then you got all the activity in Glasscock County, has given our confidence that presented market are going to be as good or better than Upton and Reagan.

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

That's fantastic. And then the last question for me is just, looking at the Davin JV that was announced this morning, which was effectively $70, $200 or so, in acre. As you guys compare the results on that eastern edge of the play versus where your wells and where you're look to JV in southern Wolfcamp area. Would your expectations be at least that much, from a per acre-type map analysis?

Scott D. Sheffield

Yes. I think, their acreage -- first of all, their acreage is more exploratory in general. They have some of it on the Eastern where there's been some pretty good Cline wells. But a lot of it moves further east into the eastern shelf. They, probably, are more limited to, potentially, 1 zone, where we have potential for up to 4 to 5 laterals in each of our -- you've got 1 in the A, you may have up to 2 in the B, because it's about 500 feet thick. You'll have some in the C and then you'll have some in the D or the Cline. So, our acreage, I think, is obviously a lot more proven. Has a lot more upside. So, obviously, should demand a much, much higher price.

Operator

Next we'll hear from Cameron Horwitz with U.S. Capital Advisors.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

With the 575 MBOE EUR that you put out here on the Wolfcamp, are you signaling that the 5 wells that you released here are 525 MBOE EURs or is that coming average of the Giddings wells and these wells or how should we think about that?

Timothy L. Dove

Well, Cameron, the way you should look at it is this, the 575,000 BOE type curve or EUR, is reflective of 7,000-foot laterals. So if you take a look at these wells in the table, on Slide 10, you'll notice they're anywhere between 5,700 feet and 6,500 stimulated lateral lengths. So these would be slightly less than 575,000 when we equilabrate [ph] or adjust the wells as if they were 7,000-foot laterals, you'll get 575,000. These will just simply be an average, it'll be slightly lower than that, based on their lateral length.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Okay, okay, that's helpful. And just in terms of the JV, have you guys already started discussions there or what's the timetable that we can expect?

Scott D. Sheffield

I said, earlier, that the data room will open in September, and bids will be due by the end of the year and then closing some time in the first quarter.

Operator

Next we'll go to Will Green with Stephens.

Will Green - Stephens Inc., Research Division

I appreciate the additional color on the Wolfcamp. Maybe you guys could help us on what you expect on a 30 day rate, what you expect on a first year decline for that 575,000 MBOE-type curve.

Scott D. Sheffield

Yes, I think it's best at some point in time. We're getting ready going to bring on several more wells. We'll actually come out as we move more toward the flow back procedure versus gas lift or jet pump. We'll be coming out with a type curve to give you that data.

John C. Nelson - Macquarie Research

Okay. Great, I'll look for that. And then you noted that you guys are going to be targeting the Wolfcamp A pretty soon. What's the timetable on going into the C bench?

Scott D. Sheffield

Right now, we're focused on a -- besides the A and the B, we're going to be focusing on the lower B. We think it's going to take 2 wells into the B, based on its thickness. And then, eventually we'll be moving into the C and also the Cline. So like I said, in some areas in that southern acreage, you can have 5 horizontals in regard to that area. But, what we call the lower B will be next after the A, and then moving into the C and the D over the next few months.

Operator

Next, we'll go to Leo Mariani with RBC Capital Markets.

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

I just wanted to ask a question here, on the potential JV. Just wanted to see if anything has kind of changed, philosophically, in you all's minds. I know, for a while, you guys had kind of said that JV is likely off the table. You guys are saying that your southern Wolfcamp acreage is going to be held by year end '13. It looks like, though, you've got the funding, at this point, to drill it up, pull it yourself. I know you talked about NEB acceleration as a result of JV, but has anything else kind of philosophically changed to want to cause you guys to JV as opposed to your thinking similarly or not you want to do that?

Scott D. Sheffield

When asked the question, Leo, over the last year, we've always been open about a potential JV as a source of funds. And we're getting more confident that this entire Wolfcamp play, and our entire position[ph], could be very profitable. And the primary reason, the JV, is that it allows us to accelerate the development of that 200,000 acres, and have somebody else cover our capital for the next 3 or 4 years. And at the end of the 3 or 4 years, we have enough cash flow to develop that. In fact, in this opportunity, the rig count gets up about 20 rigs. Just the 200,000 acres gets over 200,000 barrels a day equivalent. So it's a $25 billion investment for a total of us and a joint venture partner for the next several years. Tremendous growth. So it allows us to accelerate that and shift capital to the North where we own 100%, in Midland and Martin and Gaines Counties. That's the primary driver. And we're in a little bit lower oil price environment too.

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

Okay got you. Just a question on the EURs, the Southern Wolfcamp, you talked about the 575,000. I know you all said you come out your type curve next quarter. It looks like you got 5 new wells, I guess, a little bit more in 30 days of production history. It just -- it feels a little bit early to kind of come out with the big increase on the 5 wells. What else are you looking at, in those 5 wells, to get to the 575,000 EUR?

Scott D. Sheffield

Yes, there's a total of over -- you got 40 rigs running, there's a total of 400 wells producing, so there is lots of data. We've got 70,000 logs, lots of core data, so we got the confidence. A lot of other operators are drilling around us. We just feel like we have the confidence. There's other oil shales, like the Eagle Ford oil shale. We're also using the -- there's a good 3 years of results there, in the oil shale opportunity. So it's a combination of all those factors.

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

Okay got you. In terms of your slide deck, obviously, you've got a lot of info in there. I think you made a comment, in the slide, that your 2013, 2014 production guidance is kind of wait-and-see at this point. Is that purely just a function of what commodity prices might do in the next couple of years?

Scott D. Sheffield

Yes, we said commodity prices and service costs. It's a question of whether or not we use a $80 price deck, $85 price deck or a $90 or a $100. So it really depends on -- and that's more dependent upon on -- less in the oil and gas industry but what happens in Europe and the rest of the world. So we have to come up with a long-term price case and then we'll come out -- under almost all those cases, we're going to have double-digit growth for several years, 5 to 10 years. It's just a question of how high we can push the growth number, which is very dependent upon the price of oil.

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

And last question, on just capital cost. You kept your drilling budget at $2.4 billion, reducing activity a little bit. Can you just give us a little bit of color around where you might have seen a little cost creep to kind of maintain that $2.4 billion despite the lower activity?

Timothy L. Dove

Well, we're seeing some creep laid out in a couple of areas, and they've actually been well-documented. One is in Duar [ph], where we have been subject, at least, to some cost increases, really, throughout this year and it probably led to about, I don't know, $25 million run rate annual increase in Duar [ph], costs that we've seen over the last couple of quarters. The other thing that comes to mind is -- of course, in the Midland basin where you have -- and, actually, the whole Permian Basin, you have 540 rigs running. The number of people required to get that done is incredible, and as a result, labor cost have gone up, probably about 10% this year. I'd say those are by far and away the biggest issues when it comes inflation. The rest of the cost have been generally pretty flat this year. The other I'd just say, just to make it clear is, we have done scope changes in some of our areas. As you know, we're deepening the wells in the Permian Basin, the vertical wells, and we're actually increasing lateral lengths in some areas compared to the original plan. So some of it's scope as well, not just inflation.

Operator

Next, we'll hear from Dave Kistler with Simmons & Company.

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

Real quickly, just one more, on the JV. In terms of the structure of it, how do you guys think about it from a cash versus carry perspective? Do you have a preference for how you receive capital associated with that JV?

Scott D. Sheffield

Yes. It'll be very -- we anticipate it'll be very similar to the Reliance structure.

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

Okay, that's helpful. And then switching over to NGLs and NGL realizations. As we look at the hedges, you guys put in place for 3Q and 4Q, at over $60 a barrel of oil equivalent versus the current market, that seems like it's in kind of a $30 range. Can you talk about how you're were able to secure those or if that's relative to just a certain portion of the NGL chain, maybe the higher portion C5, et cetera?

Scott D. Sheffield

Yes, those volumes that we added were mainly on the heavier part of the stream, and so that's why you see the higher realized prices. And then we also had some propane ones that were tied to WTI. So it's really a combination of the heavier stream and then propane that we did a while back, then tied it to WTI so we're getting a higher realization. 6% [ph] Of WTI.

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

Okay. That's helpful. And then when you talk about the NGL inventory that you compiled. Again, is that segmented to a certain part of the NGL chain? I would imagine probably the higher portion of the chain.

Timothy L. Dove

No, those are just Permian NGL barrels, so they end up being 35% ethane and probably about 20% propane and 20% butane and about 20% natural gasoline. So it's sort of the typical Permian Basin NGL barrel.

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

Okay, that's helpful. Last one, looking at your decision to monetize your hedges on gas at '14 and a portion of them in '15. Was that more opportunistic as far as aggregating capital or are you, in some respects, also maybe calling a bottom on where you see natural gas prices in '14 and '15?

Scott D. Sheffield

It's a combination of both. Optimistic, at the same time preserving or maintaining our strong balance sheet.

Operator

Next we'll go to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

When you talk about accelerating drilling on the back of the JV and the Wolfcamp, can you talk to what kind of acceleration that could be? And then you may have mentioned, and it's not entirely a question, 20 rigs in the southern acreage. But where do you see your horizontal rig count going, in south plus north, with the successful JV?

Scott D. Sheffield

Yes. I've mentioned, Brian, that over time, we do have the opportunity to get up to 20 horizontal rigs. It's spending within cash flow over the next several years. The number of rigs that we move to the north, we haven't determined yet. Right now, it's just 1 rig. Depending on the results in Midland and Martin County and which is really going to be tied to service cost, the Monty prices. Going into the next 2 or 3 years will be determining factor. In addition, it's important that we live within cash flow as a company. And so, that'll be the primary determining factor in the out years, so how much we devote to those northern counties where we own 100%.

Brian Singer - Goldman Sachs Group Inc., Research Division

And then you don't need the 20 rigs, though, to hold acreage. So, from an acceleration perspective would, based on your quite bullish comments on northern potential, would you not ultimately want a higher rig count in the north than you would in the south?

Scott D. Sheffield

Yes, a lot of it depends on infrastructure ability to -- our people, too. But I said, the determining factor, the joint venture design and the rig count, is to live within cash flow. From our standpoint. So the 20 rigs allow growth -- significant growth for several years. We'll be running those 20 rigs and the determining factor after that, going up north, is our results, living within cash flow as a company and what the commodity prices are. So it's a combination of all 3, so I can't really predict how many rigs we're going to be running in the middle of the Martin County and the horizontal at this point in time.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then, at the time you issued equity last year and accelerated spending in the Wolfcamp Shale southern region to hold your acreage, you had indicated there were multiple other levers that you could pull out that [indiscernible], some of which you've done. South Africa selling this JV. You'd also mentioned selling Alaska, potentially dropping down assets to the MLP. Can you talk about where you stand on some of these other remaining levers? And should a successful JV put to rest any chance of equity issuance through the end of 2013?

Scott D. Sheffield

Yes, first of all, the JV is one of the cheapest cost of capital. It's obviously another reason why we're pursuing that. But, in addition, we look at -- all of our assets are for sale for the right price. And so we will continue to look at the performance of those assets and make that determination, in the future, whether or not we should be selling an asset or not.

Scott D. Sheffield

Equity, yes. We have no plans, at all, to be issuing equity. Obviously, with the opportunity to do the joint venture by far exceeds the best way to drive the performance and bring forward the opportunities in the southern acreage versus issuing equity. We're very surprised about the comments that our IR department has heard, about us issuing equity, and the last thing we're going to do is issuing equity. We just issued last December. We do not want to be considered, like some people are, continued issuers in common equity.

Operator

Going next to Brian Corales with Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

Just looking forward, do you expect -- I mean, should we think about even lower vertical rigs, say 2013, '14, and as the increase towards outer rigs in the Permian continue?

Scott D. Sheffield

That's always a possibility. If we get the type of returns like we have in Giddings. And as we move into the north acreage, then the returns from the horizontal Wolfcamp will probably most likely exceed the vertical. We'll just have to determine, at that point in time, is it better to run more horizontal rigs and less verticals or a combination of both. It's just something we'll just have to wait and see. It's probably a decision a good year from now.

Brian M. Corales - Howard Weil Incorporated, Research Division

And as you kind of get up north, you say, into Midland and Martin, Glasscock Counties is there any concern that you'll have from previously vertically drilled wells or none of them really reached the Wolfcamp? Or minimal reached the Wolfcamp? How should we think about that?

Scott D. Sheffield

I think, the important message is that the -- from a vertical well, when we frac the Wolfcamp, it drains around 3 to 4 acres. So it essentially has no effect on us putting a horizontal well, or a series of horizontal wells, into the Wolfcamp. Just the fact that it's so tight and we're just not exposing much of the drainage area with a vertical well.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay, and just one more general question. In the Wolfcamp, how much thicker is the entire Wolfcamp section in the heart of the Spraberry trend, like in Midland County versus the southern acreage?

Scott D. Sheffield

Throughout our entire acreage position, it runs from 1,500 feet to 2,600 feet. So it does vary.

Operator

Going next to Mario Barraza with Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

A majority of my questions have been answered. But are you guys still thinking, in the northern portion of your acreage, it's still roughly 200,000 net acres, prospective, for the horizontal Wolfcamp or has that grown at all?

Scott D. Sheffield

No. Tim mentioned that we are going to be drilling wells in Midland and Martin and Gaines. So that will be our entire position, somewhere between 800,000 and 900,000 acres.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

And then, also with the JV. If you guys are able to coin and close that in the first quarter next year -- I know, in a couple of your recent presentations, you've laid out kind of your midstream plans. Do you have the midstream lined up to support such a -- the ramp up you could be targeting with the JV on the production side?

Timothy L. Dove

Yes, Mario. Of course, we're planning ahead in terms of this increase ramp up and drilling and activity, and we have participated in some firm transportation deals on oil pipelines to make sure can move the volume associated with that drilling. And most of those projects come along in 2013, about the same time that we would anticipate having the beginning points of increased production, and so that's in good hands. I think we've got expansion space on -- our NGL offtake becomes in place in early 2013. We're also expanding our own Midkiff/Benedum gas plants, from 260 million cubic feet a day to 460 million cubic feet a day by the end of next year. And the sum total of all those we think will -- best we can, avoid any kind of short term bottlenecks. Of course, we're still seeing a bottleneck in Mont Belvieu, pertaining to the NGLs and ethane rejection we mentioned. But we anticipate that would be likely done and really not an issue after the end of this year.

Operator

Our next question will come from Charles Meade with Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Going back to your guide-up for 2012, it looks like that's really being driven by the Spraberry volumes. And so, I'm curious, is that going to make the kind of incremental volumes in that guide-up more oily than the overall mix?

Timothy L. Dove

I think so. I mean, as you know, Charles, we drill those Spraberry wells -- they're vertical wells. Particularly in the early part of their life, they're making 80%-plus crude oil. So that's higher than our current production mix and so, by definition, it'll increase our oil mix for the second half of the year.

Charles A. Meade - Johnson Rice & Company, L.L.C.

Got it. And then, I guess, following up on that, for the missing volumes that you guys are going to have with ethane rejection. Is that going to -- you'd also expect that to increase your gas realizations per Mcf. Is that something that we should expect going forward?

Timothy L. Dove

Yes. Really, I mean, if you take a look at it, it's relatively small impact, is the answer.

Charles A. Meade - Johnson Rice & Company, L.L.C.

Got it. And then 2 other quick ones for me. First, Tim, when you mentioned that those XBC Giddings Estate wells are still exceeding expectations. You're referring to that new kind of 650,000 EUR expectation?

Scott D. Sheffield

Well, I'm really referring to the fact that the results of the wells, from a production standpoint of it, have been phenomenal and 7x that of a typical 140,000 vertical well. And they exhibited tremendously flat production compared to what you would expect. And as I mentioned in the call, in my slide, they're producing, on average, 365,000 BOE per day, still, which is unheard of, I guess, in the Permian Basin, in recent history. The EURs of those wells at 650,000 BOE estimate, really, is more reflective of the fact they have only 5,300-foot stimulated lateral sections. So you're going to think much, prorate up by virtue of a 7,000-foot lateral or higher. The EUR impact of that in the same area would be substantially higher than 650,000.

Charles A. Meade - Johnson Rice & Company, L.L.C.

Got it, got it. And then the last question. There's been a lot of talk about some of the cost inflation on the service side, but this is more of kind of an impressionary judgment call on your part. How much do you think that your drilling efficiencies have offset that cost inflation, in terms of kind of overall efficiency of your CapEx budget?

Timothy L. Dove

Well, we're seeing, as I mentioned also, earlier, seeing pretty dramatic increases in efficiencies of the drilling in combination of Barnett Shale -- Permian Basin, of course, we're experienced, and have a lot of rigs running so we're just flatline in terms of already having driven out most of the cost. We're definitely improving in the Eagle Ford shale, in terms of time and cost on wells. The one thing to note is, our vertical integration is saving tremendous amount of money right now. A combination of Pioneer pumping services and our well services. In fact, they are saving capital at a basis of second quarter run rate of over $270 million a year. So that's really where we're getting the cost advantage, is the fact that vertical integration is paying off handsomely.

Operator

Our next question will come Sven Del Pozzo with IHS Herold.

Sven Del Pozzo - IHS Herold, Inc

I believe Tim mentioned something about field rules. I think you said 14 horizontals per section. Am I right? Did I hear that correctly?

Timothy L. Dove

I think it's -- we could drill a minimum of 14. 14 would be in contemplation of drilling an A and a B bench well in a section and a half, that we'd be able to drill a total of 14 of those. But to the extent we were drill C or D bench wells, we can actually increase that. Of course, this is 960 acres, so the total well count would be limited to 48 wells, based on 20 acres spacing. But we could drill a substantial number of more horizontal wells based on the fact -- as long as they're in map view, relatively close to each other, they only count as 1 location. So it's plausible you could drill, for instance, 28 horizontal wells and still drill 41 vertical wells in a section and a half. So this field rule change gives us a lot of latitude in terms of being able to optimally develop this field, considering you could be looking at numerous stack laterals and then you could offset those with either existing or offset 20s. So you're looking at a substantial amount of capital to develop what would only be a section and a half in those scenarios.

Sven Del Pozzo - IHS Herold, Inc

Okay, so you'd probably be more inclined, after you hold your acreage, to develop more densely, I guess, drill more wells in a fore-given service area and because there's probably sweet spots that you're going to discover.

Timothy L. Dove

I think that's very plausible. Probably will not occur until 2014, when we finish the acreage gather, if you want to call it that. But it's something we're contemplating now.

Sven Del Pozzo - IHS Herold, Inc

Okay. And I think it was, yes, Slide 12, with the vertical Spraberry type curves and the average 24-hour IP rates shown there. What should we think about in terms of dewatering times associated with these wells for the frac water to come back, and also any formation water, when we're doing our modeling? Or are we to just supposed to say, okay, day 1, 24 hour IP rate and plug in your number?

Timothy L. Dove

No, these wells pretty much come on production when we turn the pump, and basically -- of course, you're reducing a large amount of water with that. But in the Spraberry trend area, these vertical wells, we're producing water through the life of the well. It's different in the Wolfcamp where there's not a lot of water in situ. So, in this case, Spraberry trend area, we're producing 250,000 barrels of water, everyday, from these vertical wells. And so it's not exactly the same case as when you're thinking about horizontal as compared to vertical.

Sven Del Pozzo - IHS Herold, Inc

Okay. And then the verticals for -- how about for the Strawn, Atoka and Mississippian? Would you characterize the formation water, in those formations, similar to what you said about the Spraberry trend or more like the Wolfcamp where there's not as much?

Timothy L. Dove

Much more like the Spraberry trend area.

Sven Del Pozzo - IHS Herold, Inc

Okay. And then just to quantify. How many Spraberry vertical wells were completed in the first quarter and in the second quarter? And perhaps what you're on pace for in the third quarter and then that'll be it.

Timothy L. Dove

Yes, we put 188 wells on production in the second quarter. I don't have the number from the first quarter off the top of my head, but we're still in -- sort of heading towards 650 or so, 650 to 700 wells for this year.

Sven Del Pozzo - IHS Herold, Inc

Okay. And that includes the wells that were held over from 2011? The ones that you've completed in the first quarter?

Timothy L. Dove

These are wells we put on production in the second quarter.

Sven Del Pozzo - IHS Herold, Inc

Okay. And 650, for the year, also includes the stuff that was drilled but not completed in the fourth quarter of 2011?

Timothy L. Dove

It's pretty much just a run rate number. You look at it in terms of wells put on production or drilled. We always have an inventory of wells that are waiting on completion and waiting to be put on production, so those numbers end up equating.

Operator

Our next question will be from Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I just want to ask a couple more, I guess -- not to beat a dead horse, but I'm thinking about 2013, I think previously you had indicated -- get into 10 net horizontal rigs or operating 10 horizontal rigs in '13. Is that still a fair assumption on a net basis, post-JV? How should we think about that?

Scott D. Sheffield

Yes. Right now, we are -- without a JV, we're planning going to 7, start off the first part of the year. With a JV, it'll more likely be around closer to 10.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

And is that net or a gross operated number?

Scott D. Sheffield

That's a gross number.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And is there any willingness to outspend in '13, a modest amount, given that you're growing debt capacity and you can still drive leverage metrics lower with the growth you're seeing? Or is the mantra literally spot-on with cash flow, it's going to be the target coming end of the year?

Scott D. Sheffield

No, our long-term strategy is to grow within cash flow.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then, I guess, last one on my end. Just thinking about kind of targeted lateral length. Is that 7,000 the current assumption or there -- is it likely to be a little lower than that, just based on field limitations?

Timothy L. Dove

Well, I think the objective is to, at a minimum, drill 7,000-foot laterals because there's, clearly, a very close correlation between lateral lengths and well productivity, EUR. But as I mentioned in the call, we're going to be exploring the use of up to 9,000-foot laterals in the second half of this year. So we'll have more to report as more time goes by, as to this correlation. And, of course, your lease configuration ends up being a determinant. To the extent you can actually drill more than 7,000 feet, it takes the least configuration to do so. So it certainly won't be in every case we could exceed 7,000 acres. But the objective of the field rule change is to, in fact, provide for the opportunity to drill, at a minimum, 7,000-foot wells.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. So that's a fair number for '13, to kind of think about as an average?

Timothy L. Dove

Well, that's going to be above 7,000. In other words 7,000 would be the minimum. To the extent you drill some that are above that, you would exceed 7,000 on average.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then just looking at those 5 University wells. I mean, you had frac stages of like, I guess, 35 on average. The type curve you're seeing is 30 to 35 frac stages. Help me kind of think about how you've got shorter laterals but the same amount of frac stages. How's that really impact, then, the EUR assumption? Is it just overly stimulated, if you will -- or, I mean, I guess can you help bridge that a little bit?

Timothy L. Dove

There's a distinction in between the number of stages pump, and actually, the number of clusters in each stage. And so, to the extent you -- extend the laterals, you could still be running 30 to 35 stages, but you would be increasing the number of clusters in each of the stages. So, actually, you're putting more profit and more fluid away, in connection with basically increasing the number of cluster per stage.

Operator

We'll hear next from Richard Tullis with Capital One Southcoast.

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

Just quickly. What were the choke sizes? The typical choke you were using for the 24-hour and 30-day rates for those University wells in the Wolfcamp?.

Unknown Executive

Well, the average -- 20/64th.

Timothy L. Dove

20/64th, sorry, is the answer.

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

Tim, where would you likely test those 9,000-foot laterals on the Wolfcamp? What part of your acreage?

Timothy L. Dove

Well, specifically, I'm talking about the southern part of the acreage. Probably in the boxed areas on Slide 10. That is in Upton and Reagan, and perhaps over into Irion as well. Basically, it'll be a smattering of those wells, depending upon where we have the proper lease configuration.

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

Okay. And then just finally, I guess you picked up a little more acreage in the Barnett Combo, in the quarter. But given the drop in activity there, and I guess the cash demands and better returns elsewhere, is any potential to look at monetizing that asset at some point?

Scott D. Sheffield

As I had stated earlier, all of our assets are up for sale. And we will determine, over time, if we get the right price, what to do. So right now, there is no current plans.

Operator

Our next question comes from Cameron Horwitz with U.S. Capital Advisors.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

One quick follow-up. You obviously have your plate pretty full here, with the Wolfcamp. But I know you had some plans to horizontally test the Strawn, potentially the Atoka and the Jo Mill horizon. Still planning to do those tests?

Scott D. Sheffield

We have, actually, a couple of horizontal Jo Mill wells that have been drilled. We're waiting on completion of those wells, so we'll have something to say about that, perhaps next quarter. In terms of horizontal Atoka, it's something that we're looking at for later in the year or perhaps early next year. So, we're still some time off before we'll be able to report on results from that activity.

Operator

And our last question for today will come from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

I got kind of a high-level strategic question for you. It might be a few years premature. But if you're right and the Wolfcamp plays' perspective. From north to south, across your 900,000 acres. And you can target up to 5 zones within the Wolfcamp. Your inventory and your capital intensity is just going to be mind-boggling, quite frankly. You commented that you won't outspend cash flow or issue equity here, but I'm wondering, going forward, how you're going to approach, attempting to really pull the present value forward from the site, that 100,000 acres there.

Scott D. Sheffield

We look out about 5 years. I mean, 5 to 7 years, and so, I'm not really concerned. We are pulling it forward by doing a joint venture. I mean, 5, 7 years from now, if it turns out that the Wolfcamp is 5 billion to 10 billion barrels itself, then you have lots of choices at that point in time. You can do more joint ventures, you can sell other assets in the company to fund it. It depends on what commodity prices are doing, so it's a nice problem to have. So We're focused on the next 5 to 7 years, where we're going to get significant growth and us keeping the northern acreage, and a joint venture in the southern acreage. And so, it'll be something left for future generations around here.

Operator

And we actually did have one more participant queue up with the questions. Our final question will come from Abhishek Sinha with Bank of America.

Abhishek Sinha - BofA Merrill Lynch, Research Division

I just wanted to ask one question on Alaska. So what plans do you have on Alaska, in terms of Devon's share? I mean, where do we stand, now, with -- since we're talking more on the JV right there.

Scott D. Sheffield

Yes, on Alaska, with our two recent strong results this past winter campaign. We were getting prepared to drill a second Torok well onshore next winter. And then, secondly, we have a series of frac candidates in the Nuiqsut to perform. So we're looking forward to the next winter's campaign.

Abhishek Sinha - BofA Merrill Lynch, Research Division

All right. So do I read that Devon's share is still on the table or you're not talking about Devon's share anytime soon? Or...

Scott D. Sheffield

No, I think it's important for us to sit there and -- we have a lot of upside. We need to understand that potential upside before we make any long-term decisions.

Operator

And with that, we have no further questions. I'd like to turn it back over to our presenters for any final and closing remarks.

Scott D. Sheffield

Again, we thank -- I know a lot of questions about the Wolfcamp and the joint venture. We appreciate the opportunity to speak with you all today. Look forward to the next quarter and continue to update on this tremendous resource potential in the Permian Basin. Again, thank you.

Operator

And ladies and gentlemen, once again, that does conclude today's call. Thank you for your participation and have a wonderful day.

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