先鋒自然資源 (PXD) 2014 Q2 法說會逐字稿

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 Webcasts.

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 a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties are described in Pioneer's news release on page 2 of the slide presentation, and in Pioneer's public 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.

Good day, everyone, and thank you for joining us.

I'm going to briefly review the agenda for today's call. Scott is 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 process 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 results and plans in the Spraberry Wolfcamp, and he'll also touch on the 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.

Thank you, Frank. Good morning.

I'm on slide number 3 on financial and operating highlights. Second-quarter adjusted income of $195 million or $1.35 per diluted share. The second-quarter production significantly above the 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 of 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 the 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% to 19%, we're narrowing 16% to 19%. Obviously, the first half has been much better than expected during 2014.

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, and 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 2014, continue to support the same EURs we've been showing with very strong returns.

Going to slide number 4, financial and operating highlights continuing. We have assigned and are finalizing an agreement with the city of Odessa and Midland to allow us to use about 360,000 barrels a day of affluent water. We have mentioned occasionally that we'll, over time, over the next 10 years, will 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 two major agreements with both cities. So we're 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. We placed another 17 wells on production in the upper targets, and very excellent results with the continued down spacing, and also the staggered program. As we have mentioned, as you have 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 they 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'll announce the sale of Hugoton, the Kansas asset to Linn Energy for $340 million. Expect to close by the end of the third quarter of 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 third quarter of 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 in 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 2014, the rest of 2014, at very good prices and also in 2015. And with the run-up over the last month to two months ago, we did increase our coverage in 2016.

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 of Cushing or LLS, as we move barrels down to the Gulf Coast. We have a strong balance sheet at the end of the second quarter, with net debt to book of 25%.

Turning to slide 5, regarding production guidance. Again, we are above the first half. Came in at -- with Hugoton, we show a breakdown with Hugoton and without Hugoton. 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 to 186. 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 number 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 had showed you in early May during the announcement of first-quarter earnings, but 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 SWOC, in the southern JV area going from first half to second half, but a 3.5 times increase in the north. With the increase in rates from 5 to 16.

Slide number 7, in regard to capital spending. We're still on track on drilling capital to 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, we'll fund the rest of the growth during the year.

Slide number 8, on Eagle Ford shale condensate exports. Pioneer has been involved, we put a team together. Focused on this over the past 12 months.

We did ask the Department of Commerce if they agreed with our definition that 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 400,000 barrels, most of it was Pioneer's. It 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 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 US. We are still working with Congress and the 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.

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 production about 34 wells since the beginning of 2013, with the split shown in the table below.

Predominantly, those wells have been drilled in a combination of 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 are acreage we're not even showing having drilling any wells yet, and that's simply because we're waiting the finalization of acquisition of 3D Seismic in order to make sure that we know essentially where not to drill where they are drilling hazards.

And as he mentioned as well, the production data from all these areas really are continuing to follow our earlier data, and there's more information on the next slide regarding that. We also placed three horizontal drill mill shales wells on production, and three middle Spraberry shales during the first half of the year. I've got a graph coming up in a couple of slides.

We have had relatively mixed results on those intervals. The best two drill mill wells are tracking about 800,000 barrel BOE type curve. I've got a graph to show you that, as I said, in a couple slides.

But, in the third well, we had plug failures which negatively affected the completion on the well, 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 fracking interference from adjacent horizontal wells in some cases. So the bottom line is, on these two particular zones, it's going to take more work to determine whether these are economically prospective as compared to the four 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 Wolfcamp B, where we have the most wells. That curve is shown in the blue.

And the Wolfcamp B, of course, has really been a tremendous producer. It looks pretty clearly like the average well now is 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 I'd 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 definitively that Wolfcamp A can produce of those sort of levels. But it's certainly encouraging.

Turning now to Wolfcamp D, which is shown in the purple curve. We have six wells in the D, and 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 shales, seven wells in various areas. As we've explained for some time, the green curve does exhibit a different shape than what we 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 that does look like, from the green curve, the lower Spraberry shale 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 one 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. A 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 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 one 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 a very interesting result.

In the case of Jo Mill, that's shown in the green curve, we have two wells. Again, they're relatively short laterals at about 5,500 feet. It 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 of 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 two zones are going to fit in our future development plans.

Turning to slide 12, it's been a very busy year in the north. Actually, the photo on the bottom right is the less true of that. We showed a photo last quarter of four rigs lined up drilling the 11 wells that are in this hut lease area, and here you see these wells being completed.

It looks like we've effectively put in place a city in the hut lease. And at this time, we have seven of those wells on production, four more to be put on production. And the wells look very good so far. So, we are very active, and will continue to be very active in the hut area, as well as several other areas for 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 year, it's going exceedingly well.

We have, as Scott had mentioned and we've 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. This ration has stayed the same since the last quarter.

Again, drilling three well pads, still we're averaging spud to pop ties of about 145 days, which results in the back weighted production that's been well publicized. In 2014, our well costs are still ranging $8.5 million to $9 million, about 8,200 feet of lateral length on average.

We continued to reduce our vertical rig count. We're now down to nine rigs, expect to reduce to six by the end of this year or early 2015.

What we're doing is we're renegotiating some of the leasehold so as to not have to drill wells to deal with continuous development clauses, and that allows us to then reduce the rig count. That said, rig efficiencies on 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 the 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 that 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 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 -- to five instead of four, generally which reduces the number of stages and saves time. In a lot of cases, increasing profit per foot. Some cases from 1,100 pounds per foot up to 1,700 hundred 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 and are just starting up right now, I believe we will not see any significant results till early next year. So we're very busy in the north, is the summary of the slide, and 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 links 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 three well pads, and still focused on the three Wolfcamp zones.

Of interest, is the fact we drilled our first Wolfcamp D well. And you see 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.

So that extends the D prospectivity well into the south. And importantly, we have three 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 an 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 you look out say 8 to 10 years, we're going to be at 80 to 120 rigs.

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 of the locations are going to be drilled and in what order for 10 years.

We're obviously working very hard on marketing and take away 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 a day.

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 the other plant planned for next year, the 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 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 them. But you have to have the take away ready in terms of infrastructure. Because we have an extremely active infrastructure build out that's front loaded, because it has to all 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 salt water 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. We also began, about a month ago, taking brackish water into the southern operations 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 we have 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 are 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 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 message is here, our long-term logistics and planning efforts are giving us confidence that we can avoid the road blocks and obstacles that would allow us to fully execute on this accelerated plant. 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. Now that's both the short term and long term, and we are seeing just that in the Spraberry Wolfcamp area. You can see that our production was up 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 that were from the vertical drilling.

The production was up from about 86,000 barrels a day, due to the horizontal production growth from the wells and more efficient gas processing operations. By repairing gathering system, 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 when 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 to flush production in the first quarter. As all those wells were brought back online 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, and on a percentage basis, we did shut in [more] production that was closed by horizontal fractures 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, three well pads. And that leads to, as has already been mentioned, growth in the second half of the year, with this very significantly weighted in that direction.

Scott showed of the 58 wells that are 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 we're right on schedule for POPs in the Permian basin.

So in summary, there were very strong operating results for the Midland basin this quarter, and it gives us confidence in our ability to execute into the future.

Now turning to Eagle Ford, that's slide 16. This slide is an update of our recent activity when it comes to down spacing 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 can see down below in a gun barrel view, down spacing from 500 feet down to between 175 to 300 feet, depending upon where you are. We did put 17 of the upper target wells on production in the first half. The results look 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 down spaced with 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 that gives us a lot of encouragement that the number of locations we've added in the upper target are real. And they're actually adding a 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 had 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 three and four well pads.

Importantly, I think about 90% of our wells this year, we've used a two string casing design instead of three string design where we can. Which saves a tremendous sum 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 these 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] to the rate and adding more clusters per stage as examples of the optimization. And in some cases, a combination of all of 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.

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 non-cash mark-to-market derivative losses of $137 million after tax, or $0.94. That was principally related to the increase in Ford oil prices that happened during the quarter.

We also showed and are including the quarter a loss on discontinued operations of $57 million or $0.40, and that was principally related to the Barnett shale. So adjusting for these items, we are at $195 million or $1.35 per diluted share.

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

Turning to slide 19, we'll 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 of $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 payments. So all in all, you can see we've got a great financial position with plenty of liquidity, and that will be further strengthened with the completion of our asset sales later this quarter.

Turning to slide 22, and focus on third-quarter guidance. I think probably the most important thing is just recognize these numbers exclude Hugoton, that that will be included in discontinued ops, along with Barnett in the third quarter, prior to those asset 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.

(Operator Instructions)

We will take our first question with Doug Leggate with BofA Merrill Lynch.

Thanks, good morning, everybody. Thanks for getting on the call. My first question I guess, I've got two if I may.

First one is to Tim. Tim, you mentioned you've got seven of the newer wells and the hut lease online. I guess there you're really just trying to up the completions for the first south drilling program. But I also understand that the lateral lines are quite a bit longer than your guidance. So I'm just wondering if you could 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's quite impactful to the production outlook.

And I've got a follow up please.

Thank you, Doug. First of all, it's a little bit too early to tell how these wells are going to produce. For example, two of them we're just put on production yesterday.

So they are cleaning up, and the early results look very good. But I can't give you an IP number yet, because we're really not there yet. But the wells are cleaning up, and we have four more to produce. Frank, do you have the lateral lengths on those hut wells?

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

I guess really what I'm trying to get at is that 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 tying to get at.

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 averaging 8,200, 8,300 feet, 8,400 feet, even 9,200 feet in SWOC, southern Wolfcamp areas. 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.

Okay. Maybe my follow-up will help clarify. Because my follow-up is really on the activity level as well. Because when you get into 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, maybe as the annual add as opposed to just the 5. So what I'm trying to understand is where are you on the rig negotiations?

Is it, obviously, you've got to plan these things quite well ahead of time. So can you give us some idea as 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 the tolerances are, and how we should think about the true level of activity as we go over the next 18 months? And I'll leave it there, thanks.

Yes, Doug, this is Scott. As we have said publicly, we are 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 affects going into 2015. So we're right in the middle of deciding and looking at obviously commodity prices. We've seen a $7, $8 drop in the last two weeks in crude oil, for reasons like Argentina.

So I've generally been more bullish about oil prices with what's going on in the Middle East. But Brent is falling off too, so we've really got to decide what's the best plan.

I'm pretty confident we'll at least add 5 rigs, and hopefully we can add more than that. So we'll make that decision over the next several weeks to months.

All right. Thanks, fellas.

And the lateral length will definitely be increasing significantly in both the South and the North, continually.

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

Morning, guys. 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 a result of drilling efficiency gains, really at the drillbit, or on the completion site?

I think, Dave, this is really a reflection really that 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.

Okay. And then I guess as a derivative question the 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?

Well I mentioned that we have certain areas where we are reducing costs. For example, in the Eagle Ford, I mentioned the very significant cost savings now that we've decided to go very fully essentially into two string casing design. And that's substantial when you're talking about 100 wells or so that you basically are in the 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 costs all across the board there. And one way were doing that is just on days. You may remember, we talked a little about continuous operations, about 24 hour simultaneous operations in fracking wells.

That's a tremendous savings in days. It can be upwards of 8 to 10 days, and in our business of course time is money.

So, it's really combination of those areas. We're trying to nick away at the costs. We're not seeing really a lot of cost creep in the first place, and that's certainly helping us.

Okay, I appreciate that. And then just last one here, when you quote $8.5 million to $9 million well costs in northern Midland, you also put in quotes science costs included. What's the ultimate target well cost if you were to extract the science component?

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, and micro size I think it's $2 million per well. So, of course we're not doing that in every well.

We're only doing that in certain areas where we're drilling, where we need to get the data, we're we haven't already drilled and/or have that kind of science. I think what happens though, if you look at that on average, we'd probably compare away $400,000 to $500,000 per well. If you look at after this year because it's probably quarter of those wells that we're doing the science work on.

Perfect. I appreciate the color guys, thanks so much.

Incidentally, this is to Doug's question before. The average hut horizontal well is 7,300 feet.

Okay. Great, thanks guys.

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

Good morning, guys.

Scott.

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

Yes, that's right. The middle Spraberry wells we feels like we probably -- and I mentioned it in the call, we probably drilled too close to some of the offset verticals, and you probably see some depletion effects from that. So we just have to do the study of that, how far do we need to stay away from vertical wells. Because you can see, in the case of the one well, it looks like pretty good results.

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 than maybe Jo Mill at this point?

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

John, I'd just add that if you'll will 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 had it here in this most recent well. But that's behind us now we think, because we're not using those plugs anymore.

Okay. And then just my one follow-up question. You all have 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 scene is available in 2016. Can you just quantify for me how big the expansion is, and if just ballpark if there's any capital costs that you all have already worked through?

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 a expansion that we expect to begin in 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 it will 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.

Great, thanks, guys. Appreciate it.

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

Hey, guys. Just wanted to ask you a couple of questions about your production guidance here. Just looking at 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 talk us through some of the dynamics there? Is third-quarter maybe a little conservative given that it sounds like you're on plan with POPs, and just maybe discuss the big ramp in 4Q and how we should think about it?

Yes, Leo, Scott. If you look at our third-quarter POPs in the North, we got 31 on slide number 6. A lot of those are going to be toward the end of the quarter. So then you've 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 into 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.

Okay, that makes a lot of sense. Just in terms of asset sales, I guess I was little surprised to see the Hugoton on the tape here yesterday. I guess just a question if anything else is planned in the near-term on the asset sale side?

Yes, I've already made the comment on Eagle Ford. And long-term, we have done a tremendous amount of work on both the West Panhandle and Raton over the last two years. And we're finding a tremendous amount of opportunities behind the pipe pay in both the Raton assets and the West Panhandle asset.

So those assets we actually, and even at today's gas prices, with some liquids, West Panhandle, you'll probably see us put a little capital into those assets over the next several years and key production plant to growing those assets.

A lot of opportunities, 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. So it's been a great asset for us, and it's better to redeploy the capital back into the drilling more horizontal wells.

Okay, thanks guys.

We will go next to Brian Singer with Goldman Sachs.

Thank you, good morning. Vertical integration is 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, take away in the context of your ten-year plan?

Do you need to be more vertically integrated in the form of midstream entities that would increase CapEx near-term, but could become MLPs longer term? Or should we expect longer-term partnerships with existing midstream companies?

Yes, I think, Brian, long-term, we think it was very important on the midstream side, for instance, we do our own a piece of every processing plant with both analysts and WTG. It gives us more say so then 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, 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 two-thirds one-third. Two-thirds internal, one-third external. Obviously, if prices get out of hand if like they were back two or three years ago that we could divert from that. But we can generally see the two-thirds one-third 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. And as more and more people go out to increase the size of their frac jobs, I anticipate sand prices continued to go up.

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 work over units, pulling units, which we've expanded significantly, will continue to have probably somewhere around half of our total pulling units, Company-owned. So we're seeing big benefits there. So it allows us to execute safe capital, and able to drill wells much cheaper than our competitive peers.

Great, thanks. 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?

Yes. First of all, the only condensate we produce in the 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.

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 shales plays down in the Delaware are producing condensate.

And so there's been talk as that condensate moves into the Midland basin and transported, the market is going to have to figure out a way to get it out of 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 we're not producing any condensate.

Great, thank you.

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

Good morning, gentlemen. 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 I wanted to -- if you could comment on perhaps some changes to the overall program in the southern JV from this interesting well?

I think you're right, Arun. It definitely gives us some encouragement. A well that makes 2,100 barrels a day from the D zone we think is really an outstanding well. And just information, it was about a 9,900-foot lateral, so this is reflective of the fact that a lot of laterals we're drilling the South are out in that 9,000 to 10,000, in a couple cases over 11,000 range.

And I'm just hopeful as we look to the next two or three wells that are 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 one well, but it certainly is extremely encouraging. And I'll have to leave it at that until we're ready to see the rest of these D wells get drilled.

My next question -- thanks for that, is just on your mineral interests. I know there's been a lot of market interest in mineral interests and 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. I was 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?

As you know -- you're correct. We have about we calculate 68,000 acres gross, and as 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 this situation. I think right now, we'd probably leave it at that. We don't have a tremendous amount of net acreages 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 it's certainly something we're watching.

Okay. Thanks for that detail. 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 wells. I was 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?

I think it's really -- you're looking at wells that are one or two offset wells in the area. Is sort of varies by area, but it's not a section that you shut him. It just depends upon how close the wells are, and on the geology.

So I think the way I would look at is, it's usually one and/or two offset wells. So those are big producing wells that are offsetting where the wells are getting completed, then you take a production hit. And it could be significant if you've got to shut in a 1,000 barrel a day well.

Thank you for that.

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

Yes, good morning, everybody. I recognize 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 two of your best wells, the Flanagan, Spraberry well is doing, and how I believe that was the ETO Daniel was not the highest Q, but it was the highest spot rate Wolfcamp B Well that you guys had had?

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

Great, thank you. And, Tim, going back, and this might be one of the things that we need to, to use your term, tap the brakes on. But the completion improvements you guys have had in the Eagle Ford are really impressive, particularly in conjunction with the 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, in that you think a lot of what you've learned in the Eagle Ford can be transferred pretty directly over to the Wolfcamp. So I'm wondering, is that something that we should look for? Or is this something that -- is that going to be incorporated into expectations going forward, or is that something that we need tap the brakes on?

Well, we don't have any data on it, Charles. I will tell you that you're right, it has 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 use different ways to optimize.

Some areas we can just pump more profit per foot. Some areas we do a combination of ways to optimize. But 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 as the Midland basin. Some zones may take a different sort of optimize completion as compared to others.

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 the 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 SPE in October addressing exactly what they did in the Eagle Ford. So that will 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.

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

They're not the same, is the point.

Okay. Great thanks Tim.

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

Good morning, guys. Two quick questions for me. In the Eagle Ford as you guys continue the down spacing program, I was wondering if you could give us some context in regards to the incremental success?

If you have incremental success on the down spacing? Where your inventory [doubts] would move to? And how that would correspond to the number of years you have remaining in your drillable inventory?

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.

Okay, great. And then in regards to the Eagle Ford, he 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 incremental room to run from here in terms of testing additional proppant or tightening the stages further? Or if you think you found the right recipe in regards to your completion techniques in the Eagle Ford?

Well I think we've gone a long way after two years of understanding what works in what area. But we're always working on incremental changes. One example would be using brown sand.

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 sand where possible.

White sand is very tight along the lines of the question Scott answered, about the sand market. So if we can use our own brown sand, then we're in pretty good shape.

Thank you. And my last follow-up here, just in regards to the current tight curves you guys are seeing in the Eagle Ford with the enhance 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?

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 the Eagle Ford as well. So that's the amount of return, and we'll calculate it based on the amount of EUR we add compared to the amount of capital we're spending.

Thank you very much.

I wanted to get back to Charles. You had a question about the two 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 hut C number 1H, it 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.

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

Thanks, good morning.

Hello, Michael.

Yes, I guess I just wanted to dive a little bit more into the mix shift that we saw during the second-quarter. In particular, just any additional guidance or commentary around how that should trend into the third quarter? And what the various components likely do quarter-on-quarter by you're thinking?

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 that's reflective of the horizontal drilling. Which, as Scott said, we're going to be [yelling] with incremental volumes that are 75% oil, with the balance being a combination of dry gas and NGLs.

If you look back, we've already mentioned the increase in the horizontal oil drilling campaign, both from the Spraberry, Wolfcamp and Eagle Ford shale. But then also that was offset by the fact that we had the effects of the flush production the first-quarter, when production was probably, you could say, arbitrarily increased by turning a lot of new wells on with flush production after the bad weather.

And, of course, shut-ins hurt us as well. We do, of course, as a result of producing the oil, also produce incremental gas and NGLs in all of these areas, particularly Eagle Ford, where we had a significant amount of new gas. Eagle Ford we produced 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 came to, for example, in our midcontinent gas and NGL production. So really I think if you looking 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 quarter-on-quarter affect.

And then similarly, you're not going to have the affect as much in terms of having incremental gas production coming out of improvements at the gas plants, that's now behind us as well. And we can count on that higher level production going forward.

Michael, this is Frank. Let me just add a little color on what Tim just said.

The first half basically our liquids were about 66%. And I don't have the exact calculation front of me, but I did the other day. Oil is pretty close to 50% of our mix now.

You see us going out a couple years from now on 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 on our Northern acreage.

And I was saying, that fact that you also subtract a lot of gas in Barnett and Houston.

Yes, that makes sense. Helpful, thank you. And of that, just a real quick follow-up on that. You mentioned on the offset horizontal completion that you had a shut in. About how much was that on a total basis for the quarter roughly?

Was it 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.

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 it wasn't a lot in the first quarter, so that ought to give you an order of magnitude.

Perfect, that's helpful. And then just continuing a little bit more on the mix questions. Can you just remind me how the EUR splits are expected to vary North to South, and reservoir to reservoir?

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 which zone. So an example is, the lower Spraberry shale calculates in its life to have in the mid-80%s in terms of oil production, and this would be really principally the day that we have there is in the north of course.

It would 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 D, which is deeper and by definition you're going to need 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 Wolfcamp A and B in the 70%s, as well as the Jo Mill and the middle Spraberry in the middle 70%s. So it depends on which zone more than where the wells are being drilled.

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

I think that what you have to look at in the first hand, the cost of delivering fresh water into our operations, this is freshwater, is probably going to be currently at more than double what this water will come in that will be effluent 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.

Great, that's helpful. And then the last question of mine. Scott, you alluded to it earlier, but just the full, the potential to lift the full export ban in the US. Any thoughts or feelings on potential timing on that from where you stand?

Yes. We are making progress on the education process. I think most people see it very beneficial.

What's happening with the Ukrainian situation in the Iranian situation has been very helpful in regard to providing both LNG and oil to our neighbors in both Asia and Europe. So I'm optimistic by between now and the next administration, 2017, no later than 2017.

Great. That's helpful. Thanks, guys.

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

As you move to it's longer laterals across the Permian, and when you have a solid contiguous acreage, I was just wondering is lease geometry the only limiting factor? Or do you see other different risks as you get longer? And if you could comment across zones what you (inaudible)?

I think you're precisely correct. The number one issue is lease configuration that we have enough leasehold, so as to honor our lease line limits as well is drill long laterals. As I mentioned, we actually have 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 cost and the additional risk with the potential in terms of incremental oil production. 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 of depleted zones which cause loss of circulation issues. So you'll 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. In a scenario where we could lose the well and/or have a fishing job or some need for a sidetrack because of lost circulation. So it is different in different zones.

Thanks for the color. You've mentioned in the past how, and this is a [buildup] question, I apologize if I missed your comments earlier. You've mentioned in the past how once you get a good sense of leasehold's potential, and maybe a good sense of the Spraberry zones, that you will be in a better shape of may be optimizing your Northern acreage (inaudible). This is a (inaudible) inventory, I just wonder where you are right now in that lifecycle if you would?

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. If 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 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 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 bit more time and in the fullness of time we'll be able to evaluate the whole [seriotam] of opportunities and decide how to go about the optimal development plan. Considering you don't want to drill necessarily every zone, 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. For example, I think early next year, we'll plan to drill a Clear Fork well, it would 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 -- it would I think interesting to see longer laterals than what were drilled prior. So all of these zones and even more zones than those have potential, it's just going to take quite a bit of time to get to them.

Great. Thanks for the color, guys.

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

Morning, guys. I'm sticking with the Permian, takeaway capacity. You guys are very well protected into 2015. Scott or Tim, maybe a little bit longer term view. I know Cactus and Permian Express come online in 2016, sorry 2015.

But in 2016 and beyond, what's out there? What should we monitor? And maybe from a pipeline standpoint if there's any rail take away that could be added? And then I've got a follow-up.

Yes, Rehan, Scott. We are in discussions. I can't mention any specific projects or names, but most people realize that Permian is growing about 250,000 barrels of oil per day per year.

So things start getting tight in 2017, 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, the ones that are coming on in 2015 with energy transfer and plains that we need probably another 1 million barrels a day sometime in 2017 or 2018 in the Permian basin. And obviously, I think it will get built. So stay tuned on that.

Okay. Good. And just from a development standpoint of the whole industry including yourselves go deeper into it. Transportation, water, you guys are working on, any other bottlenecks that we as investors need to continue to think about that needs to be at rest? Thank you.

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 two agreements. So water has gotten better, the Santa Rosa with some new completion techniques that we're utilizing in the Santa Rosa and brackish water zone has been very -- we're increasing the flow rates from those wells significantly.

So water has gone from a high concern two or three years ago to a very low concern. Electricity is something we're working on significantly with two electrical companies controlling most of the electricity out there, both Cherryland and Energy Future Holdings, or Encore.

So, and then takeaway capacity, people. So we feel very fairly confident we really don't see any long-term bottlenecks at this point in time.

Thank you very much.

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

Good morning, guys. My first question in the Permian with the middle Spraberry, and I appreciate the extra comments 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 to do you think of it in the second half of the year? I guess the question really is how quickly does it take you to hybrid the middle Spraberry locations?

I think that's exactly right. It's really well configuration surrounding other wells that's 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 three will pads to get developed.

So it's not something we're going to be able to basically address the solution, whether it is in fact the well spacing or not. Until we get those 150 days behind us and can see some well results. We will be testing, obviously, some more locations though.

Okay, got it. And can you just give us a quick update on 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?

If you look at the map that I mentioned earlier, the areas where we're not drilling wells is where were acquiring 3D. So the area, for example, South of Midland, we have gotten that 3D in right now and are processing it. And it's also the case in some of our other areas, we're either in the process of declaring it, and in the last stages we've been working on for couple of years.

In a couple areas, we're looking at acquiring data from other parties who own it on a proprietary basis. So I think pretty quickly we're going to be a point where you're going to see us putting stars on that map on page 9 where we're filling and connecting the dots, because most of that seismic work is behind us.

Okay. And then one last one. It looks like you drilled a couple lower Wilcox Wells in Live Oak County. Can you talk about your inventory there? And what the schedule to continue to drill is might be in the back half of the year?

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 been phenomenal.

We've drilled about 9 wells so far, all of them successful. The issue if anything is there's not that many locations in this particular area where we're drilling in Wilcox, maybe 10 or 15 more locations.

So hopefully we can translate that into other areas, since this has been so phenomenally successful. But it's one of the reasons you see that Eagle Ford production has increased on the oil side.

Okay, got it. Thank you very much.

You're welcome.

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 closing remarks.

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. And I hope that everybody has a great Summer. And we'll see you on the road, thank you.

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