Pioneer Natural Resources' (PXD) CEO Scott Sheffield on Q2 2014 Results - Earnings Call Transcript

Pioneer Natural Resources (PXD) Q2 2014 Earnings Call August 5, 2014 10:00 AM ET

Executives

Frank E. Hopkins - Senior Vice President of Investor Relations
Scott Douglas Sheffield - Chairman and Chief Executive Officer
Timothy L. Dove - President, Chief Operating Officer and Director
Richard P. Dealy - Chief Financial Officer and Executive Vice President

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division
David W. Kistler - Simmons & Company International, Research Division
John Freeman - Raymond James & Associates, Inc., Research Division
Leo P. Mariani - RBC Capital Markets, LLC, Research Division
Brian Singer - Goldman Sachs Group Inc., Research Division
Arun Jayaram - Crédit Suisse AG, Research Division
Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division
Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division
Michael A. Hall - Heikkinen Energy Advisors, LLC
Ipsit Mohanty - GMP Securities L.P., Research Division
Rehan Rashid - FBR Capital Markets & Co., Research Division
David Meagher Amoss - Iberia Capital Partners, Research Division

Operator

Welcome to the 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 Earnings and Webcast. This call is being recorded. A replay of the call will be archived on the Internet site through August 30.

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 number of risks and uncertainties that may cause actual result 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 filing 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, Mr. Frank Hopkins. Please go ahead, sir.

Frank E. Hopkins

Good day, everyone, and thank you for joining us. I'm going to briefly review the agenda for today's call. Scott's going to be up first. He's going to provide the financial and operating highlights for the second quarter of 2014, another strong quarter for Pioneer. He'll then discuss our production growth forecast and, in particular, expectations for the second half of this year based on our first quarter rig ramp in the Northern Spraberry/Wolfcamp. Scott will also update you on our capital program for this year and the recent confirmation we received from the Commerce Department that now allows Pioneer to export condensate processed through our distillation units in the Eagle Ford Shale in our midstream facilities. After Scott concludes his remarks, Tim is going to review quickly our horizontal drilling and results and plans in the Spraberry/Wolfcamp, and he'll also touch on activity in the Eagle Ford Shale. He'll then comment on our long-term growth plan that is currently being developed by our teams for the entire Spraberry/Wolfcamp area. Rich will then cover the second quarter financials in more detail and provide earnings guidance for the third quarter. And after that, we'll open up the call for any questions that the people on the call might have.

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

Scott Douglas Sheffield

Thank you, Frank. Good morning. On Slide #3 on financial and operating highlights. Second quarter adjusted income of $195 million or $1.35 per diluted share. Second quarter production significantly above guidance of 183,000 barrels a day equivalent from continuing operations. We're up 11,000 barrels a day equivalent or 6% compared to the first quarter. The growth primarily driven by successful Spraberry/Wolfcamp horizontal and Eagle Ford wells. Our Spraberry/Wolfcamp horizontal wells are still averaging about 75% oil between all the various Wolfcamp and Spraberry zones and staying fairly close to that as they produce over a several-month time period.

In addition, we had second quarter production benefited from efficiency improvements in Spraberry/Wolfcamp gas processing operations associated with our ownership in the Atlas processing plants.

We are narrowing our production guidance to the upper end of the range. We were 14% and 19%. We're narrowing 16% to 19%. Obviously, the first half has been much better than expected during '14. We're on target to nearly double the number of horizontal wells placed on production in the Spraberry/Wolfcamp from 68 wells in the first half to 125 wells in the second half. Most of that obviously primarily from the north. We'll talk more about that.

Drilling capital continues to be forecasted at about $3 billion.

Production data from our 27 Wolfcamp A, B and D wells and our 7 Lower Spraberry Shale wells placed on production since 2013 and first half of '14, continue to support the same EURs we've been showing with very, very strong returns.

Going to Slide #4, financial and operating highlights continuing. We have signed and are finalizing an agreement with the City of Odessa and Midland to allow us to get up -- use about 340,000 barrels -- 360,000 barrels a day of effluent water. We have mentioned occasionally that we'll, over time, or the next 10 years, we'll need up to 1 million barrels of water a day. This goes a long way to securing water sources that are non-fresh. We're continuing to use brackish water, other non-potable water sources in addition to these 2 major agreements with both cities. So we're very, very excited. We do have the optionality to increase our takes over and above these numbers. Eventually, we want to be over 75% over the next several years’ non-fresh water sources.

Upper Eagle Ford drilling continues. Placed another 17 wells on production in upper targets and very excellent results, with a continued downspacing and also the staggered program. As we have mentioned, as you've seen in the press, the Department of Commerce has confirmed that condensate processed at most of our Eagle Ford Shale gathering plants is a petroleum product that can be exported without a license. We'll talk more about that. We have shipped out our first cargo to Asia just last week.

We've announced the sale of Hugoton, Kansas assets to Linn Energy for $340 million, expect to close by the end of the third quarter 2014. We also announced the sale of Barnett Shale assets to an undisclosed private company for $155 million, expect to close by the end of the third quarter 2014.

In addition to the Barnett Shale, we're moving out a significant commitment that we have made with a Midstream buyer going with that asset and throughput.

In addition, I want to make a comment in regard to the media comments on our Eagle Ford assets. Our Eagle Ford assets have been rumored to be up for sale. I've always said in the past, all of our assets are always up for sale at the right price. The company has a policy not to comment on any rumors in the marketplace.

Going to derivatives. We have continued to put on derivatives in 2016. We are fairly covered in '14 -- the rest of '14 at very good prices and also in '15 and with the run-up over the last 2 -- to 2 months ago, we did increase our coverage in 2016.

We have -- in addition, with the continued differentials expanding between Midland and Cushing WTI, what's nice is that Pioneer is unaffected by that. All of our barrels are priced off at Cushing our LLS as we move barrels down to the Gulf Coast.

We have a strong balance sheet at end of the second quarter with net debt-to-book of 25%.

Turning to Slide 5 regarding production guidance. Again, we're above the first half. Came in at -- with Hugoton, we show a breakdown with Hugoton and without Hugoton. And we did increase our -- to the upper end of the range of 16% to 19%. As you notice, we do show a breakdown with Hugoton and ex-Hugoton. Hugoton is going into disc ops third quarter. And that's why you see changes in regard to the production guidance going into third quarter and fourth quarter. Third quarter is 181,000 to 186,000, you'd roughly add another 7,000 barrels a day for Hugoton to get to what we have been showing before. Again, we expect production to more than double by 2018 as compared to 2013 production.

Going to Slide #6 in regard to what's driving the production growth going into third and fourth quarter. If you look at the chart, this is very similar to what we have showed you in early May during the announcement of our first quarter earnings, that we're going from 131 to 187. But you can see if you look at the green color, we're going from 21 to 72, which is a 3.5% increase fold, and that's all in the north. So that's the big driver with Eagle Ford staying about the same as in first half, about a 10% increase in the southern JV area going from first half to second half, but a 3.5x increase in the north with the increase in rigs from 5 to 16.

Slide #7 in regard to capital spending. We're still on track on drilling capital spend about $3 billion. Cash flows increased somewhat with higher prices realized. We're up to about $2.5 billion in cash flow, with cash on hand and coming from the proceeds from our recent divestitures will fund the rest of the growth during the year.

Slide #8 on the Eagle Ford Shale condensate exports. Pioneer has been involved. We put a team together focused on this over the past 12 months. We did -- asked the Department of Commerce if they agreed with our definition that our product -- our condensate is a product. We run it through distillation units in Eagle Ford at several of our central gathering plants, it is a petroleum product. The first cargo of 400,000 barrels, most of it was Pioneer's, was exported by Enterprise in late July.

There is tremendous international interest primarily in Asia to pick up this condensate. We are receiving probably more than improved pricing. We're seeing recently significant increases and based on the discounts that we're receiving. What's more important with this, we're using extra cash flow that we are receiving to drill more wells in the U.S. We are still working with Congress and administration to remove the export ban as soon as we can over the next several months to years.

Let me turn it over to Tim to go into more detail on our assets.

Timothy L. Dove

Thanks, Scott. I'm going to start on Slide 9 with a review of an update on our activities in the Midland Basin. First, starting in the northern program, Scott has already alluded to the fact that we have had a very successful program in the North now having put on placed at -- put on production about 34 wells since the beginning of 2013, with a split shown in the table below. Predominantly, those wells have been drilled in the combination of Wolfcamp B and D and Lower Spraberry Shale.

If you look at the map on the right, we're actually filling in some of the gaps in terms of our drilling campaigns and drilling, actually, in some new areas. You'll see some of our areas or acreage, we're not even showing having drilled any wells yet. And that's simply because we're waiting finalization of acquisition of 3-D seismic in order to make sure that we know, essentially, where not to drill, where there are drilling hazards. And as he mentioned as well, the production data from all of these areas really are continuing to follow our earlier data and there's more information on the next slide regarding that.

We also placed 3 horizontal Jo Mill shales wells on production and 3 Middle Spraberry shales during the first half of the year. I've got a graph coming up in a couple of slides. We had that relatively mixed results on those intervals. The best 2 Jo Mill wells are tracking about 800,000 barrel BOE type curve. I've got a graph to show you that, as I said in the couple of slides. But in the third well, we had plug failures, which negatively affected the completion on the wells, so it's really not representative.

And in the Middle Spraberry shale, our best well looks like about a 700,000 barrel BOE type curve. We have seen possible depletion effects from nearby vertical wells and possibly frac-ing interference from adjacent horizontal wells in some cases. So the bottom line is on these 2 particular zones, it's going to more work to determine whether these are economically prospective as compared to the 4 zones that I discussed earlier.

Then turning to Slide 10. Here, we're showing the average production curves for the wells drilled to the key zones in the North area of the Spraberry/Wolfcamp play. It's getting to the point where plotting individual wells clutters the graph to the point of the graph being unintelligible, such that we're now plotting the average of all wells by zone. So let me start with the Wolfcamp B, where we have the most wells that curve is shown in the blue. And Wolfcamp B, of course, has really been a tremendous producer. Looks pretty clearly like the average well. Now it's actually over 1 million BOE as depicted in the blue curve. So that's extremely encouraging.

Now talking about the Wolfcamp A. As I said earlier, there's only been one well drilled in the Wolfcamp A in the North. It's shown here in the red. It's actually quite positive in the sense that it shows a similar curve to the B wells right at, say, 1 million BOE per well. It was a shorter lateral on average of about -- let's say about 800 feet shorter than the B wells on average. So that's extremely encouraging. Obviously, we need more data, more wells to be able to say, definitely, that the Wolfcamp A can produce at those sort of levels, but it's certainly encouraging.

Now turning now to the Wolfcamp D, which is shown in the purple curve. We have 6 wells in the D. It looks like the average of those wells is nearing about 800,000 BOE.

And finally, in the green, you see the results for the Lower Spraberry Shale of 7 wells in various areas. As we've explained for some time, the green curve does exhibit a different shape than what we'd see in the Wolfcamp. It's related to the fact that the Spraberry shales have lower pressure because they're shallower, and they have a lot more water in the system that's to be gotten off before we start seeing an improved production. But it does look like from the green curve, the Lower Spraberry shales will average, say, 800,000 to 1 million BOE. You see a spike at the end of that curve, that's because there's only 1 well that's producing at 240 days out, and that's related to having put in place an ESP in that well, which has been seen to actually be very positive across a lot of our wells.

So in essence, what we can say is these Wolfcamp zones and the Lower Spraberry Shale wells are continuing to support strong EURs, minimum of 650,000 BOE and in some circumstances, over 1 million BOEs.

Now we're going to turn to Slide 11. It shows the results for the wells of what we think are representative of what the Middle Spraberry Shale and the Jo Mill can produce in the cases where we don't have completion issues or offset well depletion or interference. First, I'll start with the Middle Spraberry Shale. This is the blue curve. This is the well -- the 1 well in Midland County that we believe is representative, and it looks like it's tracking about a 700,000 barrel type curve. Interestingly, this is a curve, which, in trajectory, looks very similar to a Wolfcamp well. So we need obviously more wells to determine what this Middle Spraberry shale well can do, but it's very interesting result.

In the case of Jo Mill that shown in the green curve, we have 2 wells. Again, they're relatively short laterals at about 5,500 feet. Looks more like the trajectory of a Lower Spraberry Shale well that we mentioned on the prior slide. On average, for these wells that we think are indicative than what a Jo Mill well can produce, about 800,000 barrel type curve.

So the bottom line is we need more data points to determine where these 2 zones are going to fit in our future development plans.

Now turning to Slide 12. It's been a very busy year in the North. Actually, the photo on the bottom right is illustrative of that. We showed a photo last quarter of 4 rigs lined up drilling the 11 wells that are in this Hutt lease area. And here, you see these wells being completed. It looks like we've effectively put in place a city in the Hutt lease. And at this time, we have 7 of those wells on production, 4 more to be put on production, and the wells look very good so far. So we are very, very active, and we'll continue to be very active in the Hutt area, as well as several other areas we're drilling.

2014 is a transition year, of course, for us. Last year was a year in which we were in the gathering of the resources. Next year, we're pretty much essentially in full development mode. So we're in that transition this year and it's going exceedingly well.

We have, as Scott had mentioned and we publicized, moved the horizontal rig count in the North from 5 rigs at the end of last year to 16 basically by the end of April. And we're on target to place about 93 wells on production during this year in the North. Most of those will be A, B, D Wolfcamp wells with the balance being Spraberry Shale wells. This ratio has stayed the same since the last quarter. Again, drilling 3-well pads. Still averaging spud-to-POP times of about 145 days, which results in the back weighted production that's been well publicized.

In 2014, our well costs are still raging $8.5 million to $9 million, about 8,200 feet of lateral length on average. We continue to reduce our vertical rig count. We're now down to 9 rigs. We expect to reduce to 6 by the end of this year or early 2015. What we're doing is we're renegotiating some of the leaseholds, so as not have to drill wells to deal with continuous development clauses, and that allows us to then reduce the rig count. That said, our rig efficiencies and the vertical program are increasing such that we still expect to place the 200 wells on production that we had planned for this year even with a lesser number of rigs.

Going on to the completion optimization program. You may recall in the Eagle Ford, we had a similar program over the last couple of years. It was very successful. The idea here is to implement something similar in Midland and Martin Counties early in their program, so as to cut out a couple of years of learning curve and get to the point where we're actually completing these wells on an optimized basis. And in a similar vein, using some of the same techniques used in the Eagle Ford such as increasing the clusters per stage that are pumped from 5 -- to 5 instead of 4 generally, which reduces the number of stages and saves time. In a lot of cases, increasing proppant per foot. In some cases, from 1,100 pounds per foot up to 1,700 pounds per foot and reducing fluid volumes, which, of course, allows us to reduce our water utilization by perhaps up to 15%. Because of the back-weighted nature of these projects that are just starting up right now, I believe we will not see any significant results until early next year. So we're very busy in the north is the summary of this slide. We have a lot of activity going on.

Turning now to the South, to the JV area on Slide 13. Here, we plan to put 100 wells on production for this year. Longer lateral lengths in general, about 9,400 feet. Actually this year, we've drilled about 10-or-so wells that are in excess of 10,000 feet and a couple that are near 11,000 feet. So we are pushing the envelope in terms of lateral length in the South, mostly using 3-well pads and still focused on the 3 Wolfcamp zones. Of interest is the fact we drilled our first Wolfcamp D well. You'll see it here in the map, it's basically down in Upton County near the Reagan County line. And this well came in at about 2,100 barrels a day, and so that extends to the prospectivity well into the South. And importantly, we have 3 more wells that are planned in the second half of this year that we need to watch to see if they compare well to this last well. If they do, that means we've got a lot of running room with the D in the South.

Right now, most of the drilling is focused in the northern areas of the southern acreage, which we think is very prospective in these Wolfcamp zones, about $8 million drilling costs.

On Slide 14, Frank mentioned this in his earlier comments, we're beginning extremely important internal project, which has to do with developing a 10-year growth plan for the Permian Basin, Spraberry/Wolfcamp, Midland Basin operations, and realizing if we add 5 to 10 rigs a year and if we look out say, 8 to 10 years, we're going to be at 80 to 120 rigs. And so we need to start planning for what that means now. And on this chart, you can see various things we're working on, all the way from optimizing a development plan for 10 years, which has us putting what we call sticks on a map showing where all locations are going to be drilled in what order for 10 years. And we're obviously working very hard on marketing and takeaway issues. We need more oil pipelines probably by 2017, gas and NGL pipelines similarly and fractionation in Mont Belvieu.

In terms of gas processing, we're close to full capacity in the Permian Basin, which goes to show you how fast the Permian Basin associated gas is growing. We now are almost at capacity of 460 million cubic feet today. Our new Edward plant should be on production in about September or October. About 200 million cubic feet a day added, which will give us a lot of spare capacity and then plan for next year, middle part of 2015, adding another 200 million cubic feet a day.

On the procurement side, we are going to be in need of a lot of things like tubulars and services and artificial lift equipment and so on, and we're meeting with a lot of our providers to help have them be a part of this 10-year plan.

On infrastructure, obviously, when it comes to the drilling of these wells, it's one thing to drill and we have to have the takeaway ready in terms of infrastructure. So we have an extremely active infrastructure build out that's front loaded because it has all to be done in advance of the production.

So I'll give you an example. When it comes to multi-well production facilities, we have 22 in progress in the Permian Basin, with 16 planned for the second half of the year. And similarly on things like saltwater disposal facilities, we have 5 of those facilities in progress with 18 planned for the second half of the year. So this is a very substantial part of -- our activity here is to build out these multi-well facilities to be prepared for the ramp-up in the drilling campaign.

Scott already mentioned our transactions with the cities of Midland and Odessa for effluent water. And we also began about a month ago taking brackish water into the Southern operations to -- in the amount of about 60,000 barrels a day. So we're really making very good inroads with our new company Pioneer Water Management to begin the process of dealing with our 10-year needs in terms of water.

Electricity is really an issue to the extent that in a lot of these areas where have a relatively remote operations, and so that becomes something that we have to build out to. And of course, when it comes to other power sources, we're working very hard on evaluating CNG opportunities for rigs, as well as for frac fleets in terms of their power needs. And we can use the associated gas in the field. We're working on plans for that as well, which would be really tremendous cost savings. We'll see how that works in the future and be giving you more information when we have that flanged up. Obviously, roads are an issue out there and housing, and we're working with local government authorities to begin the process of preparing for this growth.

So I guess the messages here are long-term logistics and planning effort that are giving us confidence that we can avoid the roadblocks and obstacles that would allow us to fully execute on this accelerated plan in a very safe and environmentally friendly way.

On Slide 15, ultimately, the test is in how your production and cash flow growth is going, and that's both the short term and long term. And we aren't seeing just that in the Spraberry/Wolfcamp area. You can see that our production was up about -- to about 92,000 barrels a day. We placed 40 wells on production in these combined areas versus a plan of 39. So right on target. We also placed 57 wells on production from vertical drilling.

The production was up from about 86,000 barrels a day due to the horizontal production, horizontal production growth from the wells and more efficient gas processing operations. By repairing gathering systems, Atlas has done a great job of reducing losses, and also adding additional compression has the effect of reducing system line pressures. And all of those have the effect of increasing production. And recently, with the gas plants getting essentially full, we have better NGL recoveries went operating near capacity. So all of those have led to substantial increases in net production.

Oil production was essentially flat because mostly due to a very significant part of that related to the fact that we had the flush production in the first quarter as all those wells were brought back on line after the bad winter we had at the end of the fourth quarter. And that had the effect of semi-artificially boosting first quarter production. Also, on a percentage basis, we did shut in more production that was close by horizontal fracs, just to protect that production as well, in the second quarter compared to the first.

In the year, we still plan to put about 193 wells on production, 68 wells in the first half going to 125 in the second. Again, 3-well pads. And that leads to, as has already been mentioned, growth in the second half of the year in this very significantly weighted that direction.

Scott showed that the 58 wells planned to be put on production in the third quarter for this area -- actually, third quarter to date, we have put 10 on production in the North and 10 on production in the South, in other words, 20 wells. So right on schedule for our POPs in the Permian Basin.

So in summary, there are very strong operating results for the Midland Basin this quarter. It gives us confidence in our ability to execute into the future.

Now turning to Eagle Ford at Slide 16. This slide is an update of our recent activity when it comes to downspacing and staggering the wells, particularly into the upper targets of the Eagle Ford Shale where we expect to place about 50 wells in the upper target of the shale during this year as a part of that program.

You could see down below, on a gun barrel view downspacing from 500 feet down to between 175 to 300 feet depending on where you are. We did put 17 of the upper target wells on production in the first half. The results are very promising. In fact, they look similar to or, in some cases, even exceeding the offset well. And you can see this in the graph to the bottom right where you have the parent well, which is then being downspaced with an upper and lower target wells and you can see those wells are actually exceeding the parent well in this particular case in Live Oak County. So I think this is a lot of encouragement that the number of locations we've added in the upper target are real, and they're actually adding significant amount of value.

Finally, on Slide 17. That all shows up in record production growth and record production levels. We put 31 wells on production in the Eagle Ford this quarter versus 26 in the plan that we've showed you in the last call. And we have record production as a result 47,000 barrels a day. We expect to put 125 wells on production for the whole year in the Eagle Ford we're also using 3- and 4-well pads. Importantly, I think about 90% of our wells this year, we've used a 2-string casing design instead of 3-string design where we can, which saves a tremendous sum of money, $750,000 to $1 million per well just in the casing design.

The completion optimization still looks good. This is the basis I mentioned that we've now taken the same concepts to the Permian Basin. We think we still are adding 20% to 30% EUR increases, which far exceeds the additional cost to drill and complete the wells. For example, using more proppant, pumping fluid at a higher rate and adding more clusters per stage as examples of the optimization. And in some cases, the combination of all the above. It depends on the location, of course. And that model, we think, will work well in the Permian as well, and we're excited to see those results as we get to the end of the year and into early next year.

So with that, I'm going to pass it to Rich for a discussion of the second quarter financials and guidance for the third quarter.

Richard P. Dealy

Thanks, Tim, and good morning. I'm going to start on Slide 18 where we show net income attributable to common stockholders is $1 million or $0.01 per diluted share. That did include noncash mark-to-market derivative losses of $137 million after tax or $0.94. That was principally related to the increase in forward oil prices that happened during the quarter. We also showed near included in the quarter a loss on discontinued operations at $57 million or $0.40, and that was principally related to the Barnett Shale. So adjusting for these items, we're $195 million or $1.35 per diluted share.

Looking at the bottom of Slide 18, you can see where our results came in relative to guidance. And all items were within '14 guidance or above guidance, as Scott mentioned, particularly on production where we're above the guidance. So I'm not going to go through this in detail, but they're there for your review.

Turning to Slide 19. Look at price realizations. We did benefit during the quarter from a 4% increase in oil prices up to $95.87. It's a nice uplift there. That was offset by declines in NGL price realizations and gas price realizations. Those were down 8% and 9%, respectively. So all in all, a good quarter on oil prices and with the mild summer and strong gas injections, a little pressure on gas prices.

Turning to Slide 20. Production costs for the second quarter were $13.96. As you can see from the chart there, they're consistent with prior quarters, so nothing unusual to report on this slide.

Turning to Slide 21 on our liquidity position. We did have a net debt of $2.2 billion at the end of the second quarter that did include $445 million of cash. Our credit facility at $1.5 billion is completely unused, and we've got no near-term maturities as you can see from the schedule down there on our debt payment. So all in all, you can see we got great financial position with plenty of liquidity and that will be further strengthened with the sale of our -- or completion of our asset sales later this quarter.

Turning to Slide 22 and focus on third quarter guidance. Probably the most important thing is just recognize these numbers exclude Hugoton. That will be included in discontinued ops along with Barnett in the third quarter prior to those assets being -- sales being completed. So production guidance of 181,000 to 186,000 that Scott mentioned, and the rest of these items are all consistent with prior quarters and here for your review. So I'm not going to go through those in detail, but they're there.

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

Question-and-Answer Session

Operator

[Operator Instructions] We'll take our first question from Doug Leggate with Bank of America Merrill Lynch.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My question, I guess, is I've got 2, if I may. First one is for Tim. Tim, you mentioned you've got 7 of the newer wells on the Hutt lease on line. I guess, they're -- you really just start to crank up the completions for the first half drilling program. But I also understand that the [indiscernible] lands are quite a bit longer than your guidance. And so I'm just wondering if you give us some indication as to how those wells are performing and what the impact of -- what proportion, I guess, of your wells are going to be longer than your standard 7,000-foot guidance because obviously, that was quite impactful to the production outlook. And I've got a follow-up, please.

Timothy L. Dove

Yes, thanks, Doug. First of all, it's a little bit too early to tell how these wells are going to produce, because unlike -- for example, 2 of them were just put on production yesterday. So they are cleaning up and the early results look very good. But I can't give you sort of an IP number yet because we're really not there yet. But the wells are cleaning up. We have 4 more to produce. Frank, do you have the lateral lengths on those Hutt wells?

Frank E. Hopkins

No, I don't unfortunately. We'll get -- I'll get them for him.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I guess what I'm really trying to get at is all your guidance numbers, even the updated guidance for this year, if I'm not mistaken, are you still using standard 7,000-foot laterals in that guidance? And if so, how does that compare to the actual wells that you're drilling? That's really what I'm trying to get at.

Timothy L. Dove

Yes, the guidance is based on 7,000-foot wells and, in fact, I think I said in my presentation, Doug, that the fact that we're -- in or out on 8,200, 8,300 feet, 8,400 feet and 9,200 feet in Southern Wolfcamp area. So in fact, we still believe that lateral length is essentially linear with productivity. And so I think we should see results that reflect that.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay. Maybe my follow-up will help clarify. My follow-up is really, I guess, on the activity level as well. Because when you gave us your activity outlook, I guess, at the beginning of the year, it was based on strip pricing. Strips obviously come up $10 already, and you started to talk about between 5 and 10 rigs. So what -- maybe as the annualized [ph] as opposed to just the 5. So what I'm trying to understand is where are you on rig negotiations? I mean, is that -- obviously, you've got to find these things quite well ahead of time. So can you give us some ideas to how you see the visibility because it just seems to us that although you've raised the guidance a little bit this morning, it really doesn't take into account either lateral length or a step-up in activity. So I'm really just trying to understand where your balances are and how we should think about the real -- the true level of activity as we go over the next 18 months, and I'll leave it there.

Scott Douglas Sheffield

Yes, Doug, this is Scott. As we have said, publicly we're looking at 5 to 10 rigs per year over the next several years. We're right in the middle of planning. We can't wait until November, as you said, we've got to add the rigs going into -- fairly quickly to see production effects going into 2015. So we're right in the middle of deciding. We've been looking at obviously commodity prices. We've seen a $7, $8 drop in the last 2 weeks in crude oil or very, very -- for reasons like Argentina. So I'd generally been more bullish about oil prices with what's going on in the Middle East, but Brent's falling off, too. So we really got to decide what's the best plan. I'm pretty confident, we'll at least to add 5 rigs and, hopefully, we can add more than that. So we'll make that decision over the next several weeks to months. And the lateral length will definitely be increasing significantly in both the South and the North continually.

Operator

And we'll take our next question from Dave Kistler with Simmons & Company.

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

Real quickly. Looking at the POPs you delivered in Q2 and then what you have for the second half guidance above the schedule you'd previously given us, is that really as a result of the rigs ramping up a little bit faster or more efficiently than planned? Or is that the result of drilling efficiency gains really at the drill bit or on the completion side?

Timothy L. Dove

Yes, thank you, Dave. This is really a reflection of the fact we are seeing drilling efficiencies improving, probably about 10% this year in terms of the number of -- feet per day if you want to measure it by that or cost per foot, any of those measures. And that has the effect of having more wells ready to put on production. So I think it really is drilling efficiencies to a great extent.

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

Okay. And then, I guess, as a derivative question to that, CapEx is remaining unchanged despite the fact that you're increasing those POPs. Can you talk about where those cost savings are being incurred that's facilitating the ability to increase the number of wells delivered?

Timothy L. Dove

I mentioned that we have wells in certain areas we are reducing costs, for example, in the Eagle Ford, I mentioned a very significant cost savings that now that we've decided to go very fully, essentially, into a 2-string casing design. And that's substantial when we talk about 100 wells or so that you basically are in a situation in which you can do that math and figure out the cost savings. So that's an example where we're getting cost savings. We also are trying to, at the margin, reduce cost all across the board there. And one way we're doing that is just on days. You may remember we talked a little bit about continuous operations, about 24-hour simultaneous operations in frac-ing wells. That's a tremendous savings in days. It can be up 8 to 10 days, and that's -- in our business, of course, time is money. So it's really a combination of those areas we're trying to nick away at the cost. We're not seeing really a lot of cost creep in the first place, and that's certainly helped us.

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

Okay. Appreciate that. And then just last one here. When you quote $8.5 million to $9 million well cost in Northern Midland, do you also put in quotes "science cost included"? What's kind of the ultimate target well cost if you were to extract the science component?

Timothy L. Dove

Yes, I think if you look at it, the science costs on these wells when we're really after it, which means, basically, drilling pilot holes, taking these sophisticated logs, cores and so on and micro-seismic is $2 million a well. So of course, we're not doing that in every well. We're really doing that in certain areas where we're drilling and we need to get the data where we have already drilled and/or done that kind of science. I think what happens, though, if you sort of look at that on an average, we could probably pare away $400,000 to $500,000 per well, if you look at it after this year, because it's probably 1/4 of those wells that we're doing the science work on. Incidentally, this is to Doug's question before, the average Hutt horizontal well is 7,300 feet.

Operator

And we'll go next to John Freeman with Raymond James.

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

First question for me, Tim, when you talked about the mixed results at Jo Mill in Middle Spraberry, it seems like the Jo Mill was explainable just with that, the plug failure on the one well. Am I understanding correctly that the depletion of fact in the frac interference, was that just on the Middle Spraberry wells and not Jo Mill?

Timothy L. Dove

That's right. The Middle Spraberry well, we feel like we'll probably -- well, I mentioned it in the call, we probably drill too close to some of the offset verticals, and you probably see some depletion effects from that. And so we just have to do a study of that, how far do we stay away from vertical wells because you can see in the case of the one well, looks like pretty good results.

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

So is it safe to say that maybe when we say mixed results, maybe the Middle Spraberry is the one that's a little bit more in that camp and maybe Jo Mill at this point?

Timothy L. Dove

Yes, I would say that because remember, we have 2 outstanding Jo Mill wells in the Giddings area. That was now, what, 2 years ago, seems like. And so these wells here add on to the belief that the Jo Mill, when drilled, completed properly, has really good potential, so I would say that's exactly right.

Frank E. Hopkins

John, I would add that, if you recall, we had a couple of Jo Mill wells last year that didn't have great results. But again, that was this plug issue that we ran into and we add it here in this most recent well. But that's behind us now, we think, because we're not using those plugs anymore.

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

Okay. And then just my one follow-up question. You talked about in the past about the need to expand the Brady mine, and I believe you're going to look at doing that next year with the hope that that's completed and then that additional sand is available in '16. Can you just quantify for me kind of how big the expansion is, and if -- just ballpark, if there's any capital cost you've already kind of work through?

Timothy L. Dove

Yes, the current capacity of the mine is about 750 million tons a year. We're going to be adding an additional 1 million tons per year in an expansion that we expect to begin early next year, and it will be available for early 2016. And so that's important. We won't have any significant amount of capital this year, but next year would probably be $70 million or so. We haven't got the final numbers because the final engineering is being done right now, but that's what I expect.

Operator

And we'll go next to Leo Mariani with RBC Capital.

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

Just wanted to ask you a couple of questions about your production guidance here. Just looking at sort of what you guys are guiding, you're basically saying a little bit more modest growth on the third quarter, but then your fourth quarter production is really up pretty significantly, roughly 10% sequentially by my math here. Can you maybe just kind of talk us through some of the dynamics there? I mean, is third quarter maybe a little conservative, given that it sounds like you're on plan with POPs and just maybe kind of discuss the big ramp in 4Q and how we should think about it?

Scott Douglas Sheffield

Yes, Leo, Scott. If you look at our third quarter POPs in the north, we've got 31 on Slide #6. A lot of those are going to be in the -- toward the end of the quarter. And so -- then you got 41 going into the fourth quarter, and those are pretty well scattered out. So that's why you see a big driver going into the fourth quarter. So you don't get a full set of production numbers from those third quarter POPs until the fourth quarter. And then you put on top of that another 41 POPs. So it really sets up a tremendous fourth quarter for us.

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

Okay. That makes a lot of sense. And just in terms of asset sales, I guess I was a little surprised to see the Hugoton on the tape here yesterday. I guess just want to ask if anything else is sort of planned in the near term on the asset sale side.

Scott Douglas Sheffield

Yes, I've already made the comment on Eagle Ford. And long term, we have done tremendous amount of work on both West Panhandle and Raton over the last 2 years, and we're finding a tremendous amount of opportunities are behind the pipe pay in both the Raton asset and West Panhandle assets. So those assets, we actually -- and even in today's gas prices, with some liquids on West Panhandle, you'll probably see us put a little capital into those assets over the next several years and key production flat to growing those assets. So a lot of opportunity. Hugoton, we just didn't see much upside in that asset. We're not very optimistic about natural gas prices over the next few years. And so it's been a great asset for us, and it's better to redeploy the capital back into drilling more horizontal wells.

Operator

We will go next to Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Vertical integration has been a part of Pioneer's strategy for some time beyond what you addressed with regards to sands to John Freeman's question. Can you just talk about how you're thinking about processing, marketing takeaway in the context of your 10-year plan? Do you need to be more vertically integrated in the form of midstream entities that would increase CapEx near term that could become MLPs longer term? Or should we expect longer-term partnerships with existing midstream companies?

Scott Douglas Sheffield

Yes. I think, Brian -- I mean, long term, we think it was very important on the midstream side, for instance, to -- we do own a piece of every processing plant with both Atlas and WTG. It gives us more say-so in regard to -- of convincing them when to build new processing plants. So that's been very advantageous over other competitors in the area. We can get tied in very quickly. And so that's been a big benefit. In regard to pumping services, I think you'll see us move down to our stated philosophy in the past of about 2/3, 1/3. 2/3 internal, 1/3 external. And obviously, if prices get out of hand like they were back 2, 3 years ago, then we could defer from that. But we generally see the 2/3, 1/3 continue to expand the sand. There's a good article in the Journal today. We're glad we own our own sand. Sand prices are going up significantly as more and more people go up to increasing the size of the frac jobs. I anticipate sand price continue to go up. We're going to be -- our prices will be mitigated by the fact that we own our own sand. So that's been a big benefit. And then items like workover units, pull-in units, which we've expanded significantly, we'll continue to have probably somewhere around half of our total pull-in units company-owned. So we're seeing big benefits there. So it allows us to execute, save capital and able to drill wells much cheaper than our competitive peers.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then shifting to condensate. You talked about exports and condensate in the context of the Eagle Ford. But can you talk about the Permian, what percent of your oil is condensate if you expect that to change over time? And should we see any impact on oil price differentials there?

Scott Douglas Sheffield

Yes. First of all, the only condensate we produce in Midland Basin is at the gas processing plants. We produce gross about 3,000 barrels a day at each of the Atlas processing plants. They're going through stabilizers at the processing plants. And so that condensate, if we can figure out a way to get it to the Gulf Coast, we probably can export it. It is receiving a discount. The -- we are not producing any condensate at any of our wells, but it's oil ranging from 38 to about 42 degree gravity. Most of the condensate that you're hearing about is coming from the Delaware. Some of the new shale plays on the Delaware are producing condensate. And so there's been talk as that condensate moves into the Midland Basin, transported, the market is going to have to figure out a way to get it out some of these pipelines and batch it or build a separate condensate line. So that's probably what's going to happen, obviously, to meet the specs. So we're essentially unaffected, except for the ownership that we have at each of these gas processing plants. So all of our shale plays are essentially oil and are not -- we're not producing any condensate.

Operator

And we'll go next to Arun Jayaram with Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Firstly, I wanted to see if -- Tim, you could maybe elaborate on this Wolfcamp D result in the Southern JV area. It seems like it was one of the better wells we've seen in that interval. And just wanted to -- if you could comment on perhaps some changes to the overall program in the Southern JV from this interesting well.

Timothy L. Dove

Yes, I think you're right, Arun. Definitely gives us some encouragement. I mean, the well that makes 2,100 barrels a day from the D zone, we think is really an outstanding well. I just -- information of that, it was about a 9,900-foot lateral. So this is reflective of the fact a lot of the laterals we're drilling in the south are out in that 9,000 to 10,000 to almost, in a couple cases, over 11,000 range. And I'm just hopeful as we look to the next 2, 3 wells we're going to get drilled, we can see similar results. So we have to sort of tap the brakes a little bit because we need to see results from more than 1 well, but certainly, it's extremely encouraging. And I've got to leave it at that until we're ready to see the rest of these D wells get drilled.

Arun Jayaram - Crédit Suisse AG, Research Division

My next question is just on your mineral interest. I know there's been a lot of market interest in mineral interest in E&P. You have one of your peers with a public entity 14,000, 15,000 acres, which garnered a pretty rich enterprise value well over $2 billion. I think you guys have commented how you have about 70,000 to 75,000 mineral acres -- 75,000 mineral interest acres in the north. Just wondering if you could comment on any analysis you've done on royalty stream and future thoughts on potentially doing something to maximize value from these mineral interests.

Timothy L. Dove

Yes, as you know -- you're correct. We have about -- we calculate 68,000 acres gross. It has -- these acres, generally speaking, have an average royalty or overriding royalty interest of about 4%. I think the question is, as we look forward, what is the opportunity? We certainly are watching the situation. I think right now, I'd probably leave it at that. We don't have a tremendous amount of net acreage is our issue, so the actual value that we could generate probably wouldn't do a lot for us considering we have so many other sources of capital. But certainly, we're watching.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay. My last quick question, Tim, in the prepared remarks, you guys talked about having to shut in some production in and around where you're doing the horizontal well. Just wondering is -- completions, is that a phenomenon that you have to do? How many sections, for example, do you have to shut in wells when you're doing the horizontal completions?

Timothy L. Dove

Well, I think it's really -- you're looking at wells, there are 1 or 2 offset wells in the area. It sort of varies by area, but it's not a section that you shut in. It just depends upon how close the wells are and on the geology. So I think the way I would look at it is it's usually 1 or 2 -- 1 and/or 2 offset wells. So those are big producing wells that are offsetting where the wells are getting completed. You take a production hit, and it could be significant if you got to shut in 1,000-barrel-a-day well.

Operator

We'll go next to Charles Meade with Johnson Rice.

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

I've recognized it was time to not put individual well results on those decline curve graphs you do. But I was wondering if you might offer an update on how the -- 2 of your best wells, the Flanagan, Spraberry wells doing and how that, I believe it was the E.T. O'Daniel was not the highest cume, but it looks like the highest kind of spot rate Wolfcamp D wells that you guys had, had.

Timothy L. Dove

Yes, Charles, I'll tell you what. If you have any other questions, I will address those. I will dig it out of our data and let you know.

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

Great. Tim, going back in the spot B, one of the things that we need to use your term to tap the brakes on, but the completion improvements you guys have had in the Eagle Ford are really impressive, I mean, particularly, in conjunction with down-spacing. And I'm wondering, it sounds like there's a little bit of a shift in tone you guys are projecting this quarter and that you think a lot of what you've learned in the Eagle Ford can be transferred pretty directly over to the Wolfcamp. And so I'm wondering is that something that we should look for? Or is this something that's -- is that going to be incorporated into expectations going forward? Is that something that we need to tap the brakes on?

Timothy L. Dove

Well, I wouldn't have any data, Charles. I will tell you, you're right, it's been very successful in the Eagle Ford. But you have to realize, even in the Eagle Ford, depending upon where you are in the Eagle Ford, we used different ways to optimize. Some areas, we can just pump more proppant per foot. Some areas we do a combination of the ways to optimize, depending upon what the rock qualities are. And I think that will be the same situation we see in different zones in the Permian Basin, as well in the Midland Basin. Some zones may take a different sort of optimized completion as compared to others. And so this is a very significant but nonetheless really important science project is what it amounts to. And you have to basically have enough baseline wells to compare your offset wells. Fortunately, in our case, we've taken the exact team that worked on Eagle Ford and plopped them into the Permian Basin. They're doing the same project. In fact, our guys are generating a paper that's going to come out in the SPE in October, addressing exactly what they did in Eagle Ford. It's going to be interesting for everybody to pick up and take a look at, and it's going to be very similar techniques that we use in the Permian Basin.

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

Got it. And then just one quick follow-up. One thing I did notice in your presentation, at least you talked about, in the Eagle Ford, pumping more barrels per minute, so higher rate. But you talked about in the Wolfcamp, pumping fewer total barrels. Are those 2 consistent because one is rate and one is total volume? Or is that...

Timothy L. Dove

They are not the same is the point.

Operator

And we'll go next to Matt Portillo with TPH.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Two quick questions for me. In the Eagle Ford, as you guys continue the down-spacing program, I was wondering if you could give some context in regards to the incremental success -- that you have incremental success on the down-spacing where your inventory depth would move to and how that would kind of correspond to the number of years you have remaining in kind of your drillable inventory?

Timothy L. Dove

Yes, I think if you look at what we've announced before, we are adding somewhere in the neighborhood of 300 to 400 locations in the upper target, and I think that's something that's been well documented by the activity.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, great. And then in regards to the Eagle Ford, you mentioned a lot of success and we've seen that early on in the results you've had on the completion design. I was wondering if there's an incremental room to run from here in terms of testing in additional proppant or tightening the stages further, or do you think you found kind of the right recipe in regards to your completion techniques in the Eagle Ford?

Timothy L. Dove

Well, I think we've gone a long way after 2 years of understanding what works in what area. But we're always working on incremental changes. One example would be using brown sand. I mean, we've been using white sand and prior to that, resin-coated sand -- not resin-coated, but ceramics, I'm sorry. And of course, where we weaned ourselves off ceramics, we're trying to wean ourselves off white sands where possible. White sand is very tight along lines the question Scott answered about the sand market. So if we can use our own brown sand, then we're in pretty good shape.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And my last follow-up here. Just in regards to kind of the current type curves you guys are seeing in Eagle Ford with the enhanced completions. I was wondering if you could provide some context around the rate of return you're seeing on those assets as you continue to see improving well results.

Timothy L. Dove

Well, what I do know is the incremental capital we're spending is basically generating 100% rate of return, and that just goes directly to the margin in Eagle Ford as well. So that's actually the amount of the return calculated based on the amount of EUR we add compared to that capital we're spending. I wanted to get back to Charles. You had a question about the 2 wells. So the Flanagan well, Lower Spraberry Shale, it's trending to look like about 1 million BOE well, which is consistent in the way it's declined from what we had reported before. It's at about 500 BOE a day after about 200 days. On the Hutt C #1H, looks also like 1 million BOE or more. It's now producing about 350 BOE per day at about 500 days. I hope that answers your question.

Operator

And we'll go next to Michael Hall with Heikkinen Energy Advisors.

Michael A. Hall - Heikkinen Energy Advisors, LLC

I guess -- just wanted to dug a little bit more into the mix shift that I saw during the second quarter and, in particular, just in the additional guidance or commentary around how that should trend into the third quarter and kind of what the various components are likely to do quarter-on-quarter are you thinking.

Timothy L. Dove

Yes, I think some of these are behind us is the way to think about it, and we probably should be proceeding with a normal mix from here on out as reflected on the horizontal drilling, which, as Scott said, we're going to be on with incremental volumes that are 75% oil, with the balance being a combination of dry gas and NGLs. If you look back, we already mentioned the increase in the horizontal oil drilling campaign, both from Spraberry and Wolfcamp and Eagle Ford Shale. And then also, that was offset by the fact we had the effects of the flush production in the first quarter when production was probably, we'd say, arbitrarily increased by turning a lot of new wells on with flush production after the bad weather. Of course, shut-ins hurt us well. We do, of course, as a result of producing that oil, also produce incremental gas and NGLs in all these areas, particularly Eagle Ford, where we have a significant amount of new gas. Eagle Ford, we produce more gas on a per well basis significantly more than we do in the Permian. Of course, one of the things that happens, of course, is you have some declines in some other areas. We did have some increases when it we came to, for example, our Mid-Continent gas and NGL production. So really, I think if you look at the anomalies in terms of the oil production being affected by, really, first quarter effects, I think going forward, most of this stuff is behind us because we won't have that same sort of quarter-on-quarter effect. And then similarly, you're not going to have the effect as much in terms of having incremental gas production coming out of improvements of the gas plants. That's now behind us as well, and we could count on that higher level of production going forward.

Frank E. Hopkins

Michael, this is Frank. Let me just add a little color on what Tim just said. The first half, basically, our liquids are about 66%. And I don't have the exact calculation in front of me, but I did it the other day. Our oil is pretty close to 50% of our mix now. You see us going out a couple of years from now and getting up above 70% on liquids. Our oil percentage ought to continue to grow on a gradual basis just because we're drilling all these oil wells in both the JV area of the Permian Basin and also in our northern acreage.

Timothy L. Dove

And notwithstanding the fact you also subtract a lot of gas in Barnett and Hugoton.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Yes, that makes sense. And on the -- just really quick follow-up on that. On the -- you mentioned the offset horizontal completion that you just shut in. About how much was that on a total basis for the quarter roughly? Is that like 1,000 BOE a day or 25% higher potential production from the horizontal program? I'm just trying to think about what the total capacity of the horizontal program is coming out of the quarter.

Timothy L. Dove

Well, in the second quarter, the difference in shut-in was about 1,000 barrels a day from the second quarter versus the first quarter. And there wasn't a lot in the first quarter, so that ought to give you an order of magnitude.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Yes, perfect. That's helpful. And then just continuing a little bit more on the mix question, could you just remind me how the EUR splits are expected to vary kind of north to south and reservoir to reservoir?

Timothy L. Dove

Yes, I think, first of all, realizing it's not north to south per se. It can be, but it has a lot more to do with the zone. So an example is the Lower Spraberry Shale calculates in its life have in the mid-80s in terms of oil production. And this would be really, principally, the data we have there in the north, of course, probably be similar in the south because the zone is going to be similar in the south as well. And you go all the way from there to the Wolfcamp B, which is deeper and by definition, you mean more gas here because it's under higher pressure and depth, you're going to see roughly 70% oil. And in between those, you have the Wolfcamp A and B in the 70s, as well as the Jo Mill and the Middle Spraberry in the middle 70s. So a bit of mixed zone more than where the wells are being drilled.

Michael A. Hall - Heikkinen Energy Advisors, LLC

That's helpful. And then on the water agreement you all talked about, is there any potential cost savings associated with that to those agreements relative to what you currently run on water?

Timothy L. Dove

Yes, I think what you have to sort of look at in the first hand is the cost of delivering freshwater into our operations -- this is freshwater, is probably going to be currently more than double what this water will come in that will be at affluent water. So notwithstanding the fact that the freshwater is way more expensive than this water on the one hand. It's also the right thing to do, to be using non-freshwater. Everything we're steering towards is a non-potable water solution.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Great. That's helpful. And then I guess last question on my end is just any -- Scott, you alluded to earlier, but just the full -- potential to lift the full export ban in the U.S., any thoughts or feel around potential timing on that from where you stand?

Scott Douglas Sheffield

Yes. We are making progress on the education process, and most people see it very beneficial. What's happening with the Ukrainian situation and the Iranian situation has been very helpful in regard to providing both LNG and oil to our neighbors in both Asia and Europe. And so I'm optimistic by -- between now and the next administration '17, no later than '17.

Operator

And we'll go next to Ipsit Mohanty with GMP Securities.

Ipsit Mohanty - GMP Securities L.P., Research Division

Have you moved towards longer laterals across the Permian, and then do you have a solid contiguous acreage? I was just wondering is the lease geometry the only limiting factor. Do you see geological risks as you drill longer? And if you could comment across zones what you observed.

Timothy L. Dove

I think you're precisely correct. The #1 issue is lease configuration that we have enough leasehold so honor lease line limits, as well as to drill long laterals. But I mentioned, we actually drilled laterals up to about 11,000 feet. There's really no technical reason that we could not expand that to longer laterals. However, these are very expensive wells, and we have to balance the costs and the additional risk with the potential in terms of incremental oil production. And so I don't think we're yet at our technical limits in any way, shape or form. We do have issues in some leasehold where we perhaps can only drill 7,000-foot wells. That said, in some of the Spraberry zones, you do have some depleted zones which caused loss circulation issues. So you see a lot of cases in our Jo Mill wells and our Middle Spraberry wells, we're drilling shorter laterals just to be protective of the well. And it's an area we can lose the well and/or have efficient job or some kind of a need for a sidetrack because of lost circulation. So it is different in different zones.

Ipsit Mohanty - GMP Securities L.P., Research Division

You mentioned the fact how -- and this is a broader question, I apologize if I missed your comments earlier. You mentioned in the past you want to get a good sense of the resource potential and maybe a good sense of the Spraberry zones and that you will be in a better shape of maybe optimizing your northern acreage potential. This is a mark to get inventory. I just wonder where you are right now in sort of -- in that kind of a life cycle, if you would.

Timothy L. Dove

Well, you can see that we are drilling some of the first wells in various different zones. So I think what you have to look at is our well inventory. You look at the Wolfcamp B, I think it's very definitive that that's going to be a quite outstanding zone. I'd say, similarly, if you look at the Lower Spraberry Shale, it looks very good. I think that the Wolfcamp A has significant potential. Wolfcamp D has already shown quite a few excellent results. So I think those, we would say, they're well -- at least well defined. We need to drill more wells in the Wolfcamp A, as I mentioned on the call. The other zones in question, Middle Spraberry Shale, Jo Mill, we need more data. So I think it's going to take us a little more time. And in the fullness of time, we'll be able to evaluate the whole serial [ph] of opportunities and decide how to go about the optimal development plan considering you can't -- you don't want to drill necessarily every zone. And so because some are going to be better than others, and we'd rather optimize around that. Realizing we haven't even drilled wells yet in some of the other zones so, for example, I think early next year, we plan to drill at Clearfork well, be our first, as well as a horizontal Atoka well. And of course, some of our colleagues in the industry have already drilled some successful horizontal wells, and I think in the Atoka. And the result would be, I think, interesting to see longer laterals than we drilled prior. So all of these zones and even more zones in those have potential. It's just going to take quite a bit of time to get to them.

Operator

And we'll take our next question from Rehan Rashid with FBR Capital Markets.

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

Just sticking with Permian takeaway capacity, you guys are very well protected into '15. Scott or Tim, maybe a little bit longer-term view. I know Cactus and Freeman [ph] Express comes on line in '16 -- I'm sorry, '15. But in '16 and beyond, kind of what's out there, what should we monitor and then maybe from a pipeline standpoint, and if there's any kind of rail takeaway that could be added? And I've got a follow-up.

Scott Douglas Sheffield

Yes, Rehan, Scott. We are in discussions -- I can't mention any specific projects or names. But I think most people realize that Permian is growing about 250,000 barrels of oil per day per year. So things start getting tight in '17. So we are in discussions with a couple other companies about lines that are going straight from the Permian Basin to the Gulf Coast. Hopefully, those projects will be announced by the end of the year. So I think educating the various pipelines, ones that are coming on in '15 with Energy Transfer and Plains that we need probably another 1 million barrels a day sometime in '17 or '18 in the Permian Basin. And obviously, I think they'll get built, and so stay tuned on that.

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

Okay, good. And then just from a development standpoint of the whole industry, including yourself, go deeper into it, transportation, water, kind of you guys are working on. Any other bottlenecks that kind of we, as kind of investors, need to continue to think about that needs to be addressed?

Scott Douglas Sheffield

As Tim said earlier, we have an entire team working on each of those components from electricity and water. We feel very, very confident with these recent 2 agreements. So water has gotten better, the Santa Rosa, with some new completion techniques that we're utilizing in the Santa Rosa. It's a brackish water zone. There's been -- we're increasing the flow rates from those wells significantly. So water has gone from a high concern 2 or 3 years ago to a very low concern. Electricity is something we're working on significantly with both -- 2 electrical companies controlling most electricity out there, both Sharyland and Energy Future Holdings or Oncor. So -- and then -- and takeaway capacity, people. So we feel fairly confident we really don't see any long-term bottlenecks at this point in time.

Operator

And we'll go next to David Amoss with Iberia Capital Partners.

David Meagher Amoss - Iberia Capital Partners, Research Division

My first question in the Permian with the Middle Spraberry, and I appreciate the extra comment on seeing some depletion in the well so far. When you look forward, is it just as simple as changing your geography up a little bit? And how do you think about that in the second half of the year? I guess the question really is how quickly does it take you to high grid in those Spraberry locations?

Timothy L. Dove

Well, I think it's exactly right. It's really well configuration surrounding other wells is the main thing we need to change up, I feel like. But when you're on 150 days before we start this process of getting more information, we're going to have to wait for the 3-well pads to get developed. So it's not something we're going to be able to basically address the solution, whether it's in fact the well spacing or not, until we get those 150 days behind us, we can see some real results. We will do testing obviously some more locations, though.

David Meagher Amoss - Iberia Capital Partners, Research Division

Okay, got it. And then can you just give us a quick update on the 3D seismic in the Permian when you're getting those data sets, and then how quickly you'll be able to process them and look at new geography?

Timothy L. Dove

If you look at the math that I mentioned earlier, the areas we're not drilling wells is where we're requiring 3D. So the area, for example, south of Midland, we have gotten that 3D into right now and are processing. And it's also the case in some of our other areas we're either in the process of acquiring it, and the last stage is, we've been working on this for a couple of years, in a couple of areas we're looking at acquiring data from other parties who own it on a proprietary basis. And so I think pretty quickly, we're going to be at a point where you're going to see us putting stars on that map on Page 9 where we're filling in and connecting the dots because that -- most of that seismic work's behind us.

David Meagher Amoss - Iberia Capital Partners, Research Division

Okay. And then one last one. It looks like you drilled the couple Lower Wilcox wells in Live Oak County. Can you talk about your inventory there and with the schedule to continue to drill those might be in the back half of the year?

Timothy L. Dove

Yes, I think we have drilled some real good Wilcox vertical wells. These wells typically come on at 500 barrels a day. They're about $2.5 million wells and really have been phenomenal. I mean, we drill about 9 wells, so far all of them are successful. The issue, if anything, is there's not that many locations in this particular area we're drilling Wilcox, maybe 10 or 15 more locations. So hopefully, we can translate that into other areas as this has been so phenomenally successful. But it's one of the reasons you'll see that Eagle Ford production has increased on the oil side.

Operator

That does conclude the question-and-answer portion of the conference. Mr. Sheffield, I'd like to turn the conference back over to you for any additional or closing remarks.

Scott Douglas Sheffield

Again, thank you for attending our second quarter. We look forward to reporting on our continued production ramp-up in both Permian and Eagle Ford in the third quarter. I hope everybody have a great summer, and we'll see you on the road. Thank you.

Operator

That does conclude today's conference. Thank you for your participation.