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Pioneer Natural Resources (NYSE:PXD)

Q1 2014 Earnings Conference Call

May 07, 2014 10:00 a.m. ET

Executives

Scott Sheffield - Chairman & CEO

Tim Dove - President & COO

Rich Dealy - EVP & CFO

Frank Hopkins - SVP, IR

Analysts

Douglas Leggate - Bank of America Merrill Lynch

Charles Meade - Johnson Rice

David Kistler - Simmons & Company

Matt Portillo - Tudor, Pickering, Holt

Brian Singer - Goldman Sachs Group Inc.

John Freeman - Raymond James

Arun Jayaram - Credit Suisse

Will Green - Stephens

Leo Mariani - RBC Capital Markets

Amir Arif - Stifel Nicolaus

Michael Hall - Heikkinen Energy Advisors

Phillips Johnston - Capital One

Sven Del Pozzo –HIS

Operator

Welcome to Pioneer Natural Resources First 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 June 1st.

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 filings made with the Securities and Exchange Commission.

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

Frank Hopkins

Thank you Layia and good day everyone, thanks for joining us. I’m going to briefly review the agenda for today’s call, Scott’s going to be up first. He will provide the financial and operating highlights for the first quarter of 2014, another great quarter for Pioneer and he’ll then discuss our capital program for the year, our production growth forecast through 2018 and our increase in resource base which is concentrated into two of the larger shale oil plays in the US the Spraberry/Wolfcamp and Eagle Ford shale.

After Scott concludes his remarks Tim will review our recent horizontal drilling results in the Northern Spraberry/Wolfcamp and drilling plans there for this year. He’ll also comment on drilling plans in the Southern Wolfcamp joint venture area and the Eagle Ford shale, Rich will then cover the first quarter financials in more detail and he will provide earnings guidance for the second quarter and after that we will open up the call for your questions. So Scott I’ll turn the call over to you.

Scott Sheffield

Thanks Frank. Good morning. Again as Frank said, another great quarter for Pioneer. First quarter adjusted income of $183 million or $1.26 per diluted share. First quarter production 172,000 barrels of oil equivalent per day from continuing operations, that does reflect Alaska and Barnett share as discontinued ops. Obviously there was above the first quarter production guidance range of 166 to 171. We’re up 8,000 barrels a day from fourth quarter 2013, 5% oil production was up 9% from the same quarter. The growth being driven primarily by the horizontal programs in both Spraberry/Wolfcamp and the Eagle Ford in the full recovery of the fourth quarter weather related production for Telmex. We’re continuing to have the same forecast for 2014 from continuing operations of 14% and 19% based on our $3 billion drilling capital budget. The key driver again is the northern Spraberry/Wolfcamp, or if you remember we’re at 5 rigs a year in 2013 added 11 rigs all during the first quarter we have 16 rigs up in running, drilling mostly three-well pads. It does takes somewhere between 140 and 150 days at Seaford production from a typical three-well pad. As well we’ll talk later about the big impact of second half production and with the top schedule we’ll show in a few seconds. We’ll be increasing our wells we’re putting on production from 125 for the first half to 175 in second half, obviously that increase is primarily driven by the northern Spraberry/Wolfcamp.

Slide number four, we did close the sales of Alaska subsidiary in April continue to pursue the sale of Barnett Shale assets. In addition we extended our Atlas gas processing agreement where we owned 27% of several plants in Spraberry/Wolfcamp area for 10 years to 2032 to really ensured long term capacity as drilling activity continue to grow.

We’re adding 400 million a day of new processing capacity coming online by the second half of 2015. The first of those plants is coming on fourth quarter in 2014 with the second plant at second half of 2015. We got coverage with our derivative of 90% of 2014 oil production at $93 a barrel, we do have upside those three way callers up to $114 a barrel for WTI. 80% of the production is protected against volatility in the Midland-Cushing oil price differential which is running today about $758 we only had about 20% expose to that number the rest of our oil is priced either out Cushing or little less in the Gulf Coast. Strong balance sheet with $260 million of cash on hand at first quarter, net debt-to-book of 27%.

Going to slide number five on drilling highlights again we’ve updated the tight curves Tim will go over, better production data from 17 Wolfcamp A, B and D well, 6 lower Spraberry shale wells continue to support our strong EURs that we have shown over the last several months. we are increasing the high end the lower Spraberry shale EUR from 800,000 barrels of oil equivalent to 1 million barrels of oil equivalent. When Tim gets goes over the tight curves you can see we add several wells that are at least 1 million or exceeding 1 million barrels of oil equivalent on a normalized 700 foot laterals.

Again, a breakdown I don’t go in to details on the table, but the big change is increasing our lower Spraberry from pass 75 to 1 million barrels of oil equivalent which returns roughly 45% at the low end to 100% plus returns on the high end. Continue to see the same type returns on the Wolfcamp A, B and D. we are increasing our activity in the lower Spraberry shale up from roughly 10% up closer to 15% for the rest of the year. Replacing our first key Jo Mill shale well and our first middle Spraberry shale well on production if you remember we did have prior issues with our prior Jo Mill shale well, but this is our first good completion on a Jo Mill shale well both are tracking lower Spraberry shale wells when you normalized to 7000 feet, so we’re very excited about both of those results.

Going to Eagle Ford, we have 12 up Eagle Ford wells placed on production through mid April, as part of our continued down spacing and staggered program results continue to be very, very encouraging. In addition we’re going to two-string design instead of three-string design it saving us somewhere between $750,000 to $1 million per well.

Going to slide number 6 on capital spending, we leaving our capital program of $3.3 billion which $3 billion for drilling capital pretty much same breakdown we’ve been using since we’ve announced our capital program. Obviously with higher prices the first four five months of the year we have cash flow up to about $2.5 billion now. The cash on hand we seated in the best year we have plenty of financial flexibility in part we continue to continue to accelerate drilling activity.

Slide number seven, regarding production growth. We are still targeting 16% to 21% compounded annual production growth for the three year period from ’14 to ’16. You can see for the year 2014, we’re at 14 to 19. You can see also on this for second quarter, our guidance range is 173 to 178. And then, obviously again, emphasizing back half loaded duty adding 11 rigs in the north for first quarter were jumping up third to fourth quarter, on average 195,000 barrels to 210,000 barrels a day. So you can see as the result increasing the number of completions in the north.

Long term, we expect to add at least five plus rigs per year in a strict price environment and in a $95 all flat environment will be adding 10 plus rigs per year long term. And again, we expect product to more than double by 2018 as compared to 2013 production.

Going to slide number 8, just to emphasize the fact that we’re second half loaded, we have a pop schedule in the number of wells from each of our three key areas; Eagle Ford, southern Wolfcamp program and then the Northern program. And if you could see, the significant increase from the 11 additional rigs that we added first quarter will be adding 50 completions in the north which will significantly get the pops up to 175 from the average of 125 to the first half of the year.

And you can see, our second quarter guidance after submitting the earlier slide of 173 to 178 again is conservative, it’s also you can see at the pop schedule, we’re adding 65 wells in the second quarter as compared to 60 wells in the first quarter.

I’m going to now turn it over to – no I got one more slide sorry. Obviously, as Frank mentioned, we said, in U.S. we have probably – what’s nice is that, we have the largest – we have a great inventory of over 20,000 locations in the largest field of North America in the southern Wolfcamp again we’re excited to get a great position that’s going to drive the company obviously for decades forward.

Let me turn it over to Tim.

Tim Dove

Thanks, Scott. First and last slide was about resource potential, but in the first quarter of 2014 we made substantial in roads in the transition from a resource texture mode to one of execution of a ramped up drilling champagne that’s focused on production and cash flow growth.

On slide 10, it’s a recap of what we’ve accomplished so far in 2013 and ’14 in the North that shows that we’ve, as Scott as already mentioned place 23 wells on production during 2013 and through the end of the first quarter. Do you really see on the map that our well control in the north, north is getting much more dense and having now pop those 23 wells in various zones through the first quarter and they are shown in the tables in the left.

What you’ll see as you look back through our production data is that, our production is proving to be more predictable in these areas as further wells are drilled in more data as accumulated and those data definitely support strong EURs and returns in this area. As Scott mentioned, we did place one of our better completed Jo Mill well shales on and in the first of the Lower Spraberry shales on production and we’ll share more about that shortly. The early performance was good very good and I’ll show you a slide on that in a couple of minutes.

Turning to slide 11, actually the next three slides are similar to those from the last quarter and have been updated with recent production results from the various zones and in this particular slide, slide 11 it’s the first Wolfcamp A and B wells and you can see really very consistent results – and what we’ve done here is essentially add another month or so of production data from our recent IR materials. And you’ll notice that the wells continue to be very consistent and in fact if you take a look at an example here at [indiscernible] a 7,400 laterals made 217 BOE in just over a year. That’s comparable of course to our own vertical drilling which would make something like a 140,000 in 40 years, just gives the idea of the capital efficiency of the horizontal champagne.

When all those data continues to point to excellent production in EUR and productions of these wells, these are actually our first six wells, of course when we have seven subsequent wells on line and all the wells do point to about in the case of 7000 foot laterals, about a million BOE for Woolfcamp B in Midland County and about 800,000 BOE from Woolfcamp A in Midland County and Wolfcamp B in Martin County. So really quite outstanding results and we think more importantly consistent results and predictable results for the Wolfcamp B and Wolfcamp A.

Turning now to Slide 12. This is similar data as it represented in the prior slide but in this case with the Wolfcamp D wells another month or so data. They exhibit a similar pattern of consistency when it comes to production and leaves us to the view that the D wells continue to show support for EURs in the 650 to 800,000 BOE range for Midland, Martin and Andrews Counties if you say with 7,000 foot lateral. One note, if you take a look at the E.T. O’Daniel well, that well a little over 9,100,000 lateral is clearly well over an 800,000 BOE well.

Turning now to Slide 13. Here in this case I’m turning to the lower Spraberry shale well results. You’ll notice that the pattern of early production in the lower Spraberry shale is very different from the Wolfcamp, owing to the fact that the Lower Spraberry shale is shallower and lower pressure and it just takes a while for the load water to be produced and for oil rates to increase.

That said here that of all the wells that are showed, of the five wells, three of these wells are exhibiting EUR production over a million BOE. And this is what has led us to what Scott had mentioned an increase to the top end of the EUR range for these lower Spraberry shales to a million barrels BOE and a headwind about 800,000 barrels. And that make some sense considering these results are really not unexpected because the lower Spraberry shale calculates to have the highest oil in place in all of the Spraberry and Wolfcamp intervals. We still believe that the production data for this we’ve seen the wells on this slide present to show well suggest the range from lower shale ratio being 7,000 – for 7,000 foot lateral is 575,000 BOE to 1 million BOE now at the top end of the range.

Turning now to Slide 14. This is production data from the recent middle Spraberry shale and Jo Mill wells that we’ve been talking about. The results on Slide 13 are also superimposed, so we compare how the middle Spraberry ratio and Jo Mill wells look versus the lower Spraberry shale results I just covered. You have to look little bit careful here because there are two wells shown, the red well is the Jo Mill well, Martin Country; the black well is middle Spraberry shale in Midland County. So I should decide as early days in the sense of the production of these wells were very importantly, they show very similar trajectory in their early days as they deep water as compared to lower Spraberry shale. So we’re encouraged by that definitely and to the fact that these wells seem to be trekking lower Spraberry shale wells which have been among our best. So we’ll continue to watch these wells to see how they compare with lower Spraberry shale and the other wells.

Move to Slide 15. With the types of production profiles I’ve just shown you it's not surprising that the returns would be very high on this drilling campaign as the payouts would be very fast and you see that in the bar charts. This was actually shown in Scott’s earlier data and the green shows BTAX IRRs for the various zones and we believe that the returns are definitely going to be strong in this campaign and they would certainly suggest that, you also see in the bottom left that we have increased the lower Spraberry shale top end EUR to 1 million BOE.

Turning to Slide 16. And now we’re really talking about what is happening through this year’s program in the north and an update here shows that it really are in the process in the north in early stage of adjusting to more of our horizontal development campaign as opposed to appraisal it's back to the idea of executing now on more of the development campaign and focused on production growth and cash flow growth. As Scott already told you, we now had 16 rigs that was a planned number, that will allow us to drill about 140 horizontal wells this year, 85% will be in the Wolfcamp A, B, and D. With the results we’ve seen so far from the Spraberry shales we now up the number of wells we’ll drill in this Spraberry shales to 15%, it had been 10% that with the results we’ve seen to successes both in lower Spraberry and the middle Spraberry shale, we think the right thing to do is allocate some more capital to these zones. Most of the drilling will be on three-well pads, it pushes spud-to-POP times to 145 days. The result of which is combination of pad drilling and adding rigs later in the year will be second half rates production growth profile.

Horizontal cause in the north generally $8.5 to $9 million and we now have about 8200 foot average lateral. We continue to operate 11 vertical rigs and that’s going to compare drill about 200 wells this year that are needed to meet continuous drilling obligations so as to preserve or leasehold fairly will be reducing our vertical rig count in the next several years as the rig count has increased from a horizontal perspective.

I would point out that the photo wells, it’s a pretty impressive photo at the bottom of slide 16, this is core rigs lined up in the hut lease in Midland County banging up development style wells. So that’s a pretty impressive photo, we have a city on the ground there in Midland county.

On slide 17, now turning to the southern JV area, we’re also continuously focused here just as we were on the north on development drilling production through development drilling, here we’ll drill 115 or so wells, a longer laterals on average at about 9400 fee and similar in terms of the fact that most of the wells were utilized three well pads. And we are now in the process of reducing our spud to POP cycle time by a few days, this is the result of sign off simultaneously putting wells on production while at the same time drilling up [indiscernible] on offset wells.

So if we have work over rigs out there in several wells to operate on the location you can say this up to eight days. And trying as many of course when it comes to being this wells on production. We still are unchanged in the sense that we will mix about two thirds Wolfcamp be with the remainder being the other Wolfcamp zones.

We are going to be focusing mostly in the Northern areas where the returns are higher, about $8 million of well. So we’re pleased to report that the JV with Sinochem is going exceptionally well here in the south.

On slide 18 then, we wanted to give you just a little bit of data on some other southern area wells. We thought we’d update you on some of the over wells are performing and you’ll see the two original Giddings wells here, these are Wolfcamp B wells having now been on production for about two in a quarter years and they have been phenomenal wells at only 5300 foot laterals. Are they are tremendous wells, they are going to look like 725,000 BOE at EURs. Of course, if we were added 7000 feet that will about 950,000 BOE.

So it gives you an idea on our two most overly wells if you want to put it that way, really show consistent performance and they are really holding up to the curves to show strong EURs. On slide 19, Scot covered this to some extent, but we’re pleased to announce that we have extended our agreement with Atlas in the Midland Basin for our ten years, the coverage area is showing actually on the map to the left here, it’s been extended into Andrews County and of course portion of Martin County. You’ll note there is an area Martin County is not covered by this particular coverage area, but the balance of Martin County is an area where we have another 30% in our third party plant is also in the process of expansion.

But as it relates to Atlas area, capacity will increase from about 455 million cubic feet a day to 855 cubic feet by the second half of next year. In the principle drivers of that are the Edward plant showing the map in the south, there is a 200 million cubic feet a plant that should come on in the fourth quarter and there are plant in the north to deal with Martin County and Andrews County production another 200 million cubic feet a day. We still retain about 27% of the interest in those plants.

Our production only makes about third of the gas process, which gives you an idea that we’re not the only operator growing production in the Permian Basin and the Midland Basin. There is a substantial other new production coming online, which means we need to stay ahead of high return bottlenecks and short term bottlenecks when it comes to moving production. But we think it’s pretty clear at this point there is another 200 million cubic feet a day plant will be required basically every year as we and the rest of the industry cranks up the drilling champagne. So the Atlas extension is really part of our continuing efforts to be forward-looking with bottlenecks in terms of processing.

On slide 20 then, as expected after all this effort, it should be culminating an increase in production and ramp up of production and the Permian is certainly delivering on that front, you see production having increased 86,000 BOE compared to 79 last year and 80 in the fourth quarter, we have put 56 wells on production across the basin in the first quarter, I’m sorry, 28 wells on production and we drilled 56. Looking forward we’re going to be drilling on total of 255 horizontal wells combined in both north and south again utilizing three-well pads and the top schedule as Scott already alluded to is very significantly back half weighted. We are drilling horizontal production as we speak our net basis grew 4000 barrels a day over the last quarter.

After in to Eagle Ford shale side 21, we’re still getting very encouraging results on the upper Eagle Ford shale testing back we put 12 up Eagle Ford shale wells on production through mid-April and results look quite excellent. We’ll be drilling another 45 upper Eagle Ford shale wells this year as a part of what we have to discussed last quarter down spacing staggering effort to move the spacing down from the original say 1000 feet to 500 feet now we went to the lower range 175 to 300 feet and staggering between the low and upper levels. Average lateral length this year is up to about 6100 feet compared to about 5000 last year. About 25% of our acreage is perspective for that upper zone.

Turning now to slide 22, we were seeing record production being set by Eagle Ford quite regularly, we’ve seen substantial increase in the first quarter to about 43,000 BOE per day from 38 last year and 40 in the fourth quarter drilled about 34 wells with 32 on production. For 110 wells schedule this year it’s going to be the basis of three and four-well pads in this case which again push us out top timing.

We are now utilizing for about 80% of our wells in the first quarter particularly two-string casing design instead of three-string design essentially it saves you days and of course casing and cost savings. We calculated it saves about 7 days we can be on the well on average of 22 days instead of 29 days by taking out one of the intermediate strings. And importantly the net cost reduction is about $750,000 to $1 million per well.

We more in detail covered in our fourth quarter goals are down spacing and optimization and we continue to see tremendous benefits probably EUR increases in the neighborhood of 20% to 30% very little capital combination of down spacing staggering emission earlier but in the case of completion optimization things like pumping more profit, pumping more high rate fluids, and altering the stages in our cluster spacing. They’re all generating tremendous returns with very little capital.

So I’m going to stop there, I can just simply say in summary from an operations perspective we are executing at a high level in midst of rapid exploration in terms of drilling particularly in the north part of the Spraberry/Wolfcamp area. And with that I’m going to pass over to Rich, he can discuss the first quarter financials and the second quarter outlook.

Rich Dealy

Right, thanks Tim. Good morning, I may start on slide 23, where we showed net income attributable to common stockholders of $123 million, or $0.85 per diluted share that did include mark-to-market derivative losses of $55 million or $0.38 per diluted share and then couple unusual items Barnett shale discontinued operations and the other of tax benefit related to our Premier Silica acquisition a couple years ago, so adjusting for those items we had $183 million or $1.26 per diluted share for the quarter.

Looking at the page 23 where we did show first quarter guidance relative to our results, so we had an excellent quarter as Scott and Tim both mentioned with results – within guidance are on positive side of guidance other than mainly G&A which was above guidance primarily due to just people related costs that were incurred to support our growth initiatives as we move throughout the year.

Turning to slide 24 on price realizations, we see a another good quarter in terms of pricing oil was up 2% $92.38 per barrel, NGLs were up 9% principally related to strong propane prices during the quarter and then gas prices were up substantially 40% at $4.81. You can see results of our derivatives activity at the bottom of this line, that’s included derivative income or loss on the P&L.

Turning to slide 25 on production cost, first quarter production cost were consistent with prior periods, as you may recall we talked about in February our fourth quarter was lower due to adjustments related third party transportation cost and then lower than estimated ad valorem tax payments during the fourth quarter so that was a benefit in the fourth quarter, got back to normal in the first quarter here.

Turning to Slide 26. The company’s financial position, still very strong financial position with plenty of liquidity as you can see with $257 million cash on the balance sheet and $1.4 billion available under our credit facility. As you saw in the press release, it's further strengthened by the sale of Alaska that happened in April and then if you look at the projection Scott talked about 2.6 billion of cash position basically cash for EBITDA, our debt EBITDA of 1 times.

Turning to Slide 27 for the second quarter guidance. This does exclude discontinued operations, so we’re showing production in the 173,000 to 178,000 BOEs per day and then if you look at the rest of the items on this page there consistent with past guidance were results of the [Indiscernible] leave those for your review and then we’ll go ahead and open up the call for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions). And we will take our first question from Douglas Leggate of Bank of America Merrill Lynch.

Douglas Leggate - Bank of America Merrill Lynch

Thanks, good morning everybody. I wonder if could take a couple of questions please. The first one Scott, I just want to ask a big picture question about guidance because I realize it's relatively recently that you gave your longer term production guidance but I want to dig into what assumptions you’re making within your EUR entities are quite white particularly in the Wolfcamp B and obviously not in the lower Spraberry, we’ve also seen I guess some reference for the strip prices as the basis of your cash flow and your spending and obviously all placing you substantially higher so I’m just trying to get a feel for what's the big thing to your guidance because it kind of strikes us that you’re probably being a little bit conservative.

Scott Sheffield

Thanks, and then no, we’re still using a lower type EUR in our analysis in regard to production growth. The average is about 700,000 to 800,000 barrels of oil equivalent, so we are not modeling 1 million barrels of oil equivalent and we’re also not modeling that allow these laterals that went out to somewhere between 8,300 and 9,300 feet. It's we are being conservative, it's best to be conservative. In regard to prices as I mentioned earlier, and we have stated publically is that we’re looking at the strip environment, the strip the rest of year is about $95 to $96. It drops down to about $80 by 2019, so that’s one of our cases, that’s the case that we’re using in the three year production and also in the five years to double production. I mean in that case we’re adding roughly about five plus rigs per year in the horizontal side in the Permian basin and then we also have a case where if crude continues to perform like it has in 2014, $95 of oil, if it stays flat for next several years we’ll be adding ten plus rigs. Obviously that case wouldn’t achieve much, much higher production growth rates. We do not have that case out there publically.

Douglas Leggate - Bank of America Merrill Lynch

You feel operationally Scott you’ve got the capability to deal with in terms of securing drilling permits and line men and I think [Indiscernible] stuff I mean it's easy just to turn up the dial that quickly you know they’ve got instead of five rigs, you got ten rigs?

Scott Sheffield

Well the team handled adding 11 rigs basically in that time period very well up in the north and so adding five to ten plus rigs I wouldn’t use the word easy but.

Douglas Leggate - Bank of America Merrill Lynch

Yeah, it means trouble.

Scott Sheffield

Yeah, over 1,600 employees in Midland, so we have the – we’re the largest employer out there, so we’re way ahead of the competition, so we’re very, very confident we can accomplish that.

Douglas Leggate - Bank of America Merrill Lynch

Thanks, my follow up is not to take away from the Permian but before in the Eagle Ford given the success that you assuming to having on the upper Eagle Ford and as we do a broad question if I made because obviously you aren’t really giving us an update on how that tape curve looks or well cost you recently but some of your competitors have been talking about this particularly ConocoPhillips, it appeared to be spending $3 billion drilling 200 wells and they are telling us that their numbers are more realistic in terms of their total spending and given that you guys are pretty much late in the CMA, I just wonder if you can give some perspective as to what the economics of roles are looking, what are your current cost are and if I need tag on the end there, any update on your view of potential condense exports in our view there.

Scott Sheffield

Yeah. That’s a long question, but economic of $3 billion on 300 that’s $15 million a well, it seems high but our well cost obviously were much less than that, so and especially with going to the two string design. So we’re still – it’s somewhere between $7 million, $8 million well cost with a 50% IRR and that’s coupled with the fact that we’re getting about $8 to $10 dollars a barrel of WTI for [indiscernible] price.

In regard to the longer picture question, we are still involved with several other independent producers discussing with the commerce department administration educating congress in regard with the importance to allow oil to be exported. We still stay [indiscernible], we think it will take a good two to three years to convince them and to allow all export. I think it’s important of this country to do it. It’s important to keep this industry moving forward. So we are still confident that something will happen at some point in time.

Douglas Leggate - Bank of America Merrill Lynch

[indiscernible] can I tell you down on the cost of Eagle Ford alluded for infrastructure what is that number?

Scott Sheffield

On infrastructure, we’re done with infrastructure -- $7 to $8 million remember we’ve put in place 13 CCPs all the pods, all the production facilities over the last four and a half years, we’re pretty much done with infrastructure.

Douglas Leggate - Bank of America Merrill Lynch

That’s extremely helpful, thanks guys. I appreciate it.

Operator

And you’ll hear next from Charles Meade with Johnson Rice. Please go ahead.

Charles Meade - Johnson Rice

Yes. Good morning, gentleman. I wanted to ask a question about the Middle Spraberry Shale and the Jo Mill Shale. It seems just a little bit out of your pattern to me, maybe I’m little bit interpreting what you are doing, but it seems a little bit out of your pattern of being conservative to say that these wells are tracking a type of given that we have – it looks about 15 days in about one and 30 days on the other. And I’m wondering if there is more – there is more data than being presenting here on this slide, it may be about pressures or total fluid rates or maybe it’s a confidence from what you are seeing that offset operators that has you guys so excited at the service stage factors?

Scott Sheffield

No. Overall, Charles, I don’t think long term it’s going to compete with the top horizons. But we need to let history play its over out. And we thought the same thing about the lowest Spraberry Shale when you first came on. And so, before we make a final decision, what’s encouraging is that that Jo Mill well is the first one we’ve got a great completion on and it’s still climbing even through today on the yesterday’s report. And so, when you when you normalize, if you notice both of those wells, the middle and the lower, I mean, middle and the Jo Mill, we’re short of laterals. One is I think 4200 feet, the other one is less 5047 – 4700 feet laterals. So when you normalize all the 7000 feet, they are right on track obviously and they are making the same amount of water, they are still performing exact same way, it’s in a lower pressure regime.

The Jo Mill if you remember has been opened up and on most of our 7000 plus vertical wells. It’s been opened up over the last 30, 40 years. The Middle Spraberry Shale has not. So we’re going to drill more wells, we’re excited about it, it’s still arguably very economical. Some of the offset operators are now opened up the Middle Spraberry Shale with very good results also. We are still the only company to my knowledge that’s drilled Jo Mill wells.

Frank Hopkins

This is Frank. I think it’s important that the point scratchers made it that we’ve exchanged some cadre with some of pears and so. We now have their Middle Spraberry Shales wells are performing. So this is much along the same lines.

Charles Meade - Johnson Rice

All right. Thanks, Scott and Frank. And then, if I could to go back to the lower or excuse me, the southern JV part of the Midland basin. I think, the slide 18 you guys have is really a – it’s very power side, just – department out, because it has that 2 plus years of data, but I’m wondering if also you could give a little bit of an update if possible on what the down spacing gas are looking like here in the south. I know there supposed to be a second half event, but you have to give me shot since we’re within month or so of that.

Tim Dove

Yeah, I think the down spacing just shows Tim we’re still working on it, we did a very large campaign at the beginning we’re still watching those well resource it turns out all the wells basically producing similarly among the [indiscernible] 12 wells, we have another big, spacing task that we’re working on over rock B which is to the east and the results actually look quite good there, we’ve down space two-well pad, either Wolfcamp B wells to about 400 feet or so about 78 are spacing compared to some offset 1000 feet up to 180 acre space was, it will take extended period of time before we have this thing figured out, but there is an example where there also wells that like performing in line with each other and so. I would just call early days we also have about three other areas in the basin where we doing offset spacing test. So you kind of have to bear with us as we get the results on this. We see areas in the – even in the north where we’re going to be doing some testing as well.

Charles Meade - Johnson Rice

That’s great detail, thanks Tim.

Operator

And your next question comes from David Kistler of Simmons & Company.

David Kistler - Simmons & Company

Good morning guys.

Tim Dove

Hi, Dave.

David Kistler - Simmons & Company

I wanted to address the redirection capital in the northern Permian with 5% more going over of its Spraberry portion of the play. When we look at those that you guys highlighted and shown in slide, it takes a longer time for them to deal water and bring production up to peak levels. With that in mind capitals going over there, but your production targets are unchanged however that the low would indicate that production would shift out to the right. So I guess the just my question is, if I’m thinking about that correctly you probably have greater confidence in the production rates -- current production rates and the full production rates of our Wolfcamp wells and the ability to hit that production target given the way that slow probably also factors in the strong 15 start to production, is that a fair way to think about this?

Tim Dove

Yeah, I think first of all, those lower Spraberry shale wells increase will be in last part of the year, so you will see very little production from that, when you look at the tight curves it gives obviously a lot more stability and much flatter production even though it comes up slower you don’t get the pop like you do on the Wolfcamp wells in a higher pressure, but you get a much better flying curves. And there is chance that even a couple of these lower Spraberry shale wells would end up being better than any of the Wolfcamp A or B wells. So eventually going in to late this year next year we’ll probably be going to some four-well pads also instead of three-well pads.

Scott Sheffield

I think I add Dave is that we’re talking about 5% of 140 wells, we’re talking about 7 wells out of the 140, so we can’t have too materialize like you would.

David Kistler - Simmons & Company

Okay, appreciate for that clarification. And then going back to the Atlas agreement, so you guys trying to accelerate the outlook there is a need for 200 million a day processing facility every 12 months versus every 18 months. Can you talk a little bit about whether that’s driven by PXD specific activity concentrated near those processing facilities that’s going to be potentially accelerated industry activity or it just production rates you spend a lot higher than you thought or there some adjustment to next, just we’re trying to kind of drill down in to why that accelerated so much?

Tim Dove

Yes. Obviously, our wells performing much better, and third party growth the Spraberry/Wolfcamp at over 250 rigs in the conversion from vertical to horizontal Wolfcamp is occurring much faster than expected over the last 12 months and continued to accelerate. So it’s combination of our growth, it’s combination of obviously the third party growth, the combination of several companies are going to the IPO market and raising capital switching the horizontal drilling so it’s a combination of all of that that’s driving the factor, where we move down from 18 months to 200 million day gas plant every 12 months and we’ve been spending time with Atlas over the last probably two years convincing them that this is a huge play, it’s the largest in the North America and we need to have plants built essentially every 12 months, they may get down to point where we may need a plant every 9 to 10 months at point of time.

David Kistler - Simmons & Company

Okay. I appreciate that, we got to mind if there are appropriate or did they have appropriate financing capacity to deliver on that?

Tim Dove

Yes, I’ve been talking to the chairman [Indiscernible] and he promised me that they have plenty of financial flexibility to keep up.

David Kistler - Simmons & Company

Great, appreciate [Indiscernible]. Thank you so much.

Operator

And we’ll hear from Matt Portillo of Tudor, Pickering, Holt.

Matt Portillo - Tudor, Pickering, Holt

Good morning guys. Just as we think about the resource potentials that continues to expand. You guys have previously given some targets on your long-term acceleration potential in the northern Midland basin. As one if you have any updated dots in regards to how large of a program that could become in regards to the rig count and as we think about kind of 2015 and 2016 what do you need to see from a well production perspective or from a pricing perspective to potentially upside acceleration in your drilling program?

Tim Dove

Yes, we have that stage earlier. Under the strip price environment, we’re adding five plus rigs per year, most of those are be in the north and then they have $95 flat case if it continue to March 4 the current year into 2015 then we’ll probably more likely adding ten plus rigs per year above the next several years. Under that scenario the growth rate will be much higher than our 16% to 21% compounded growth rate. Prices continue to go up this year, all prices start stay flat to the rest of this year we may obviously some time towards the end of the year [Indiscernible] also. Anything else?

Matt Portillo - Tudor, Pickering, Holt

And then just second question. In regards to these service cost environment in the Permian and if you can provide some color just how you’re staying cost trends and if there is any areas in particularly see some pinch points on.

Tim Dove

Yeah, Matt this is Tim. I think in general we see cost is pretty flat this year compared to last year, I think one of the main areas where we see a bump that’s coming we have to compete with is in labor. Labor is tight, it's across the board, where its rigs or pulling in it's or upstream activities, upstream operations and I think labors one of your key areas. I think as you go forward into 2015, we’ll see a bump in rig cost, we are seeing some increases being profit when it comes to well actually pressure pumping for the second half of the year. I think it's going to be substantial versus negatively really affect we’re trying to accomplish the most of the things we’re doing is internal but there are signs that we already tightening the rig count is going to increase three times not only for us but for others. And so it was a mixed bag I think right now we call it more flat other than a bit going forward we’re seeing increased potential.

Matt Portillo - Tudor, Pickering, Holt

Thank you very much.

Operator

And we’ll take our next question from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Thank you, good morning.

Tim Dove

Hi, Brian.

Brian Singer - Goldman Sachs Group Inc.

Just want to pick a little bit on the cost front, if you touched a bit on the rig completion side though wonder if you think you’re on vertical integration as partially why you’re not seeing more and may be you comment on that but I want to also touch on the midstream side which is – what impact that you expect to see on both your transportation costs and on your price realization for oil, gas, NGLs from deals like the Atlas One and then just as yours and other Permian volumes about volumes grow.

Tim Dove

Yeah, I think that the fact is our transportation cost now are in couple of different areas, one is gathering costs which in some case that have to be trekking and other cases will do in closed pipeline, those are some increases in the past but it's pretty level right now. We’re going to be moving more todays putting volumes on pipe which is lower cost, trying to about 75% gathering on pipe. When it comes to the longer transportation, so for example we’re dealing with [Indiscernible] and the new pipeline systems we’ve seen some increases in FT cost for those pipelines going forward but still they represent quite excellent opportunities for us. So make sure we can move volumes out of the Midland and avoid the Midland pushing bases differential. But overall as an example with the Atlas we grab pretty much standard POP contracts on most of our gas processing that really are just more matter of what are happening – what is happening with both NGL and natural gas prices.

Brian Singer - Goldman Sachs Group Inc.

Got it. Is there some number you could put to the operating cost per barrel impact that there are any inflationary impact you see of trying to get the incremental, trying to get more barrels out in the Permian or what you would see next year and the year after versus this year. I mean, new builds where we assume would be more expensive as we go forward.

Tim Dove

Yeah, I think new built rigs, I would say that early estimate for 2015 will be 10% higher and of course that’s not a very substantial amount of the well cost, but your completions might be in the same neighbourhood 10% higher to extended recent third parties. When you look at the rest of the operating cost, I guess, say labor is up probably 10% this quarter, like [indiscernible] is going up and that will have an effect as well. So I think we’re probably looking at 10 percentage in terms of kind of cost creep volume of 2015.

Brian Singer - Goldman Sachs Group Inc.

That’s great. That’s helpful. And then, you can essentially monetize assets over the last few years in part of balance year out as then. As we go forward, do you, and especially as natural gas prices in futures have up, do you see continued asset monetization on more of the asset front and then ultimately do you see yourself heading towards peer play Permian or peer play Permian plus Eagle Ford company.

Scott Sheffield

I think, we’re pretty much nearing on a peer play Permian/Eagle Ford Company today. We do have the gas or oil and gas NGO assets, two in Mid-Continent and the one in Raton bay very long life, very low decline rate, it gives us an option on gas long term in our – all of our drilling activity is self-funding, in regard to when you give wells a pay-out 1 to 2 years in the – whether it’s Eagle Ford or whether it’s Permian, it allows us continue to accelerate, so we have no further needs for assets investors other than Barnett. We hope to get Barnett obviously covering sometime by the end of the year.

Tim Dove

Great. Thank you.

Operator

And John Freeman of Raymond James has our next question.

John Freeman - Raymond James

Good morning, guys.

Scott Sheffield

Hi, John.

John Freeman - Raymond James

Looking at – currently with your running 11 vertical rigs in the Spraberry in your own 15 vertical rigs, I just to have a couple of questions along the lines, do you or any of your vertical rigs being used by 3 parties and overtime it’s more and more horizontal drilling starts to help me that continuous drilling obligation you have, should we assume that 18 months or so that, you may look at your selling vertical drilling rigs?

Timothy Dove

John, you are kind of a head of us a little bit. We have actually sold our vertical rigs and we do not currently operate any of our own rigs vertically.

John Freeman - Raymond James

All right. And then on the upper Eagle Ford [indiscernible] has some pretty positive comments this morning on that, following six wells one of them was pretty big. And they mentioned that and they are obviously kind of in general same area as Jo and they mentioned that they were in some cases mixing the upper Eagle Ford on the Austin Chalk, and I know you aren’t giving necessarily [indiscernible] but maybe just they need to some color you could provide the upper Eagle for what you are seeing so far.

Timothy Dove

John, I think our objective right now is to complete those wells and keep it all in the Eagle Ford. That’s just been our mandate internally from the standpoint review of science group and that’s what we are doing. So we’re really not trying to – I mean, into the Austin Chalk, sorry.

John Freeman - Raymond James

That’s great guys, great quarter.

Operator

And we’ll take our next question from Arun Jayaram of Credit Suisse.

Arun Jayaram - Credit Suisse

Good morning, guys.

Timothy Dove

Good morning, Arun.

Arun Jayaram - Credit Suisse

Tim, I just wanted to talk or see if you could elaborate a little bit on the potential improvements and things spread Spraberry shales. I just wanted to see if maybe you could use the south as a guide and just give us a sense of where you think those could go to in 2015.

Timothy Dove

By south you mean [indiscernible]?

Arun Jayaram - Credit Suisse

Yeah.

Timothy Dove

Well, first of all, that’s where the money is, we’re trying to reduce this spread the pop timing and as I already mentioned to you, we are already doing quite a bit there with regards to signoff to try to actually [indiscernible] to try to actually improve those numbers and we’ve been very successful so far.

I think the real question is, what can we do in terms of going even past three well pads to four well pads, maybe even higher and increasingly use [indiscernible] to make sure that we cut these out. What we’re also trying to do of course we’ve seen some success already over the last year or so we’ve been drilling wells there, it’s actually just reduced the time on well. So this has to do with your drilling efficiencies, it has to do with basically focus on operations and also has to do with your completion profile.

But I think the answer is, today, we’re probably out of the 130 to 140 days something like that. And I think it’s not reasonable for us over the next couple of years to drop 15 to 20 days.

Arun Jayaram - Credit Suisse

Alright. And then you end the year I guess 65 kind of horizontal wells kind of in your inventory which have been completed so 15 should start off with the pretty good healthy ramp, is that fair?

Timothy Dove

Yeah, what I think the situation with our three-well pads is we’re actually drilling – we’re actually spreading the well just drilling the surface intermediate section first and then you go back to drill lateral sections of each well, so we talk about spreading oils it really isn’t necessarily the case to our drilling well particularly we did a process in most cases we’re drilling surface intermediate and lateral therefore it’s a situation where a rig can have three well that are in progress even before the three-well pad is drilling on as wells on production. So you’re right, I mean when we have the track maker I guess you called there is top line I guess in this case, out there 60, we’re going to be in pretty good shape, we able to hit first quarter 2015 running pretty hard.

Arun Jayaram - Credit Suisse

Great, and just my final question. Scott, you talked about what kind of underpin you plan up to 2018 five incremental rigs at the trip, I know you guys have a pretty conservative board, I just wanted to see if your thoughts on. Can you generate the CapEx needs internally generated through obviously you have the Barnett shale, thoughts on funding that growth?

Scott Sheffield

Yes, if you look at the current slide that we’ve been showing, yeah, these wells pad one or two years because of the short pay up it allows us to get cash flow return so strong that it allows us to reinvest and continued to have rigs without going to equity markets or without further investors other than Barnett. So that’s even with the strip price environment going down to $80. That we adding five plus rigs per year and then as I said, the upside case of $95 flat for the next several years with obviously much – which have much higher growth rates in our 16% to 21% compounded annual growth rate under that scenario, but we adding 10 plus rigs per year and that’s again self-funding.

Arun Jayaram - Credit Suisse

That’s great Scott.

Scott Sheffield

Anything else?

Arun Jayaram - Credit Suisse

That’s it.

Operator

Okay, very good. We’ll hear next from Will Green of Stephens. Please go ahead.

Will Green - Stephens

Good morning guys. I wonder if you could talk about the, you kind of touch on completion changes you guys are seeing have an uplift on your start rates and that sort of thing. One thing you mentioned was pumping more sand. Are you guys still using Brady Brown in all the Permian? And then moving forward, looking at the ramp you guys have, will Premier Silica still serve all of that need? And are you guys doing any reason code in some of the deeper part at all?

Scott Sheffield

The answer is almost 100% we pumped in our Permian base well is Brady Brown we have a little bit of white sand that use from time to time, it’s near [indiscernible] but principally it’s almost all Brady Brown by going forward what’s going to be needed because of this substantial rig count increase Scott was alluding to is expansion of our Brady mine, I anticipate commence operations on that expansion sometime next year and have sand available in 2016. So we’re actually building up the mine to meet our needs.

Will Green - Stephens

Gotcha thanks. And then other one I had is on kind of the way these pads are going to be configured, you guys already mentioned that you’re going to be doing a little bit more Spraberry work this year. But how should we think about most of these big pads being configured? Is there going to be three Ds, is there going to be A, D, A, what do you guys think at this point is the best way to pair these wells up together, being mine folded that probably different areas of the base and the middle of it different?

Scott Sheffield

Yeah, I think that’s a great question, I mean, fantastic question we’re trying to answer this is what is the optimal combination of wells on pads, so is to optimally develop an area realizing that it’s pretty definitive especially if we’re talking about the northern areas that we have quite excellent potential in the Wolfcamp A, B, D and the lower Spraberry shale, I think you can see from the day that’s pretty definitive. At the same time we’re trying to get the day that we’re talking about earlier more fully enhanced regarding the middle Spraberry shale and more Jo Mill wells that are properly completed. So I think we kind of have to hold off until we really know that because you could be in a situation you’re doing four or five stack laterals on a staggered basis on one pad. And so then you average like multiple wells on a pad not just in this three or four in the wells per pad. So I would really kind of hold off answer that that we really understand the full data set that I think it's likely we’re going to have multiple zone stack laterals when we finally get to that campaign.

Scott Sheffield

Got you, thanks for the color guys.

Operator

And we’ll take our next question from Leo Mariani of RBC.

Leo Mariani - RBC Capital Markets

Hey guys, just want to kind of get back to the Jo Mill and middle Spraberry and the northern part of the Midland here, you guys talked that your lower Spraberry kind of have the most oil in place perhaps you can give us kind of a relative comparison of oil in place for the Jo Mill and the Middle Spraberry relative to lower here.

Scott Sheffield

I think we’ve calculate about half in each case on a per acre basis.

Leo Mariani - RBC Capital Markets

Okay that’s helpful and I guess looks like in the so in part of the Midland looks like most all what you’re doing is Wolfcamp when I gather from your presentation, is that going to need Spraberry testing anytime this year or next year in the southern Midland?

Scott Sheffield

Yes, we’re actually going to do some this year and some more next year. Most of our Spraberry shale wells are in the north half of our 845,000 acres and so that we’ll be drilling some later this year and next year in the southern half including the JB areas where we own 100% in the Spraberry rights. So we’ll be evaluating the southern 400,000 acres in some of those Spraberry shale wells over the next 6 to 12 months.

Leo Mariani - RBC Capital Markets

All right, thank you guys.

Operator

And we’ll take our next question from Amir Arif of Stifel.

Amir Arif - Stifel Nicolaus

Thanks, good morning guys. Hey Scott, I appreciate your color that you don’t need to sell any additional assets but be on which it got out there already to fund your five additional rigs as you go forward but at the same time you said you would like to add ten rigs if it keep you out of cash for 95 oil and so any thought or desire to monetize some of your midstream assets [Indiscernible] MLP or selling to an MLP to free up some of the capital that accelerated just given the success you are having in the Permian?

Scott Sheffield

Well farm rigs gets us to the 80 rigs and [Indiscernible] rigs gets us to the roughly 120 rigs at some point in time and so nobody to my knowledge in any of the shale plays have been running in between 100 not one single company. So we’re accelerating already under the current plan. In regard to – if had divested – when you divested your processing assets you essentially lose control. I’m very concerned about our execution risk would go up significantly due to the fact that we have an ownership with Atlas has allowed us to educate them and allowed us to both join together, accelerate so when you lose control of your gas processing assets, your execution risk goes up significantly higher. So that’s one of the reasons why we haven't looked at it.

Amir Arif - Stifel Nicolaus

Okay, I appreciate that. And then a quick question, you’ve given second half formed as a 195 [Indiscernible] can you give us an estimate of where you think you’ll exiting the year on your production?

Scott Sheffield

We will do that later on sometime but obviously not now but obviously that would be way over 200,000 plus.

Amir Arif - Stifel Nicolaus

Okay, and then finally on the Permian basin, it can move very well this year, and any color on 50 just for the basis or I mean is there any concern for you guys out there?

Scott Sheffield

Say it again.

Amir Arif - Stifel Nicolaus

Are you getting Permian basis?

Scott Sheffield

Oh well, yeah. It drops to the 375 in July 1st on going forward long-term and so that’s with the [Indiscernible] coming on July 1st, I mean it states pretty much better with next three to five years with our – we’ll be getting a lot of our as [Indiscernible] comes on and the expansion comes on this year and with the other two lines that are coming on in 50, we do have capacity on those one in the Gulf Coast, a lot of our crudes going to be priced off [Indiscernible] down in the Gulf Coast and so we’ll have a balanced of mostly cussing and then less pricing, so we see no need at this point of time to do any hedging.

Amir Arif - Stifel Nicolaus

Yeah, thank you.

Operator

And we’ll take our next question from Michael Hall of Heikkinen Energy Advisors. Please go ahead sir.

Michael Hall - Heikkinen Energy Advisors

Thanks, lot of them are answered. I guess just wanted to come back the question on efficiencies from a little bit different angle, as it think about 15 the sort of thing that the ratio of top the world’s drill in the northern program approach as the southern program in 2015 to have them like.

Scott Sheffield

I really thank you about them. You realizing when you’re ramping up you get this massive effect of creating a popping. If you waiting on all the operation the same option, the three-well pads and the four-well pads to get to all the wells that we put on production. Once you are at a point, we were at a run rate of rigs that are stabilized, that number comes dramatically down. Now the question is how many rigs we add next and when. So to the extent we have five, let’s just say with ten rigs in the north next year. We’ll still see that effect until we get more stabilized, but it will be much less dramatic simply because you have much bigger basic product at that point. So you’ll see less swings on opportunity basis.

Michael Hall - Heikkinen Energy Advisors

Okay. And then on the lower Spraberry and in the Middle Spraberry wells, what are difference in operating cost on those wells giving, it seems like quite a bit more watered being handled there.

Scott Sheffield

Yeah. I think you are right. You do see more water in those zones, but I think our water handling is really not going to be a very percentage of the cost increase. I would say it’s relatively immaterial.

Michael Hall - Heikkinen Energy Advisors

Okay. And then, on the topic of water, as it look out to around some activity, you and others are projecting – we’ve heard some rumours around this sourcing water in the Midland Basin and click type going forward, any color on that or doing a secure frac water?

Scott Sheffield

We are, Michael, very, very active in making sure that we have adequate water supplies and its using essentially in all the above strategy which has to do with acquiring non-potable water sources, acquiring affluent water sources from some of the municipalities using brackish water, very much limiting fresh water is the objective of all this exercise and then finally we are doing a substantial number of pilots on water recycling and clean up. We have in place a new LLC inside the company which is called Pioneer Water Management. Their main job is to get water to our locations refracting and drilling. Based on what I’ve seen in terms of early returns, we are making a tremendous amount of progress in this regards such as to in a situation where water would not be an issue. We can deliver water relatively cheaply to all of our locations. It’s going to take capital over the next several years. And so that shouldn’t be ignored but the fact is we’re all over this and I think we’re going to be very successful.

Michael Hall - Heikkinen Energy Advisors

Okay. And then on the topic of capital that the 400 million of infrastructure land and plans and 100 of [indiscernible] and other ancillary cost, how long do we kind of think about that as run rate as you ramp up like it’s an Eagle Ford you kind of had moved beyond that, how long does it work through that spending.

Scott Sheffield

I think as we dig out and it’s going to come down as the facilities, so that facilities membership gone down since June as we go into ‘15, ‘16, because we’re pretty much of what completed most of our facilities those in the Permian basin. Lane will continue, we’re still going to go after contagious acreage trying to upgrade our and achieve longer laterals. So we always have a land budget pretty much fairly equal over the next several years. And on equipment, I think Tim has probably already commented, but longer term, based on the current rates we see or probably continue to do the replacement equipment only and go and start using more and more third parties overtime. But it all depends on the power and the charges that the third party companies are charging on frac rates.

Michael Hall - Heikkinen Energy Advisors

And then, I guess, last one of mine and it’s just, as it relates to the new plant and the new build out where that was pretty constrained from a processing standpoint between and when the new plan comes on in Martin in 2015, we have enough room that present, obviously you can kind of navigate around little bit, but –

Scott Sheffield

Now, we’ve already mentioned publically that we built into our guidance for the second half of the year that, there is probably about four to five months of we’re rejecting ethylene mineral guidance. Obviously, we get a pickup in cash flow or it’s neutral. And so that’s built into our guidance. We’re looking our ways, but at this point in time we don’t know whether that we can feed off some of the gas to other operators in a system for a period of around four to five months. So that’s an upside. But right now it is built into our guidance before the – and there is a chance that we could get the plant coming on in fourth quarter up a little bit earlier also. That’s not built in also.

Michael Hall - Heikkinen Energy Advisors

Okay. Can you remind me roughly how much I guess volumes being project themselves? Is that potentially a little bit of uplift in ‘15 quantify that?

Scott Sheffield

In ’15 there is no projection, because the plants coming on right now fourth quarter of ’14.

Michael Hall - Heikkinen Energy Advisors

Yeah, that’s what I’m saying is what’s the potential uplift in ’15?

Scott Sheffield

The projection will basically start around June and to go through October and November that’s what we have built in to our guidance.

Michael Hall - Heikkinen Energy Advisors

Okay.

Scott Sheffield

It’s probably about 1000 or 2000 barrels a day net, it would represent our current projection that would be picked up ‘15 versus even when we face this issue during the second half of this year.

Michael Hall - Heikkinen Energy Advisors

Okay, that’s all. Appreciated guys, thank you, good quarter.

Operator

And we’ll now take a follow up question from Doug Leggate of Bank of America/Merrill Lynch. Please go ahead sir. Doug, your line is open.

Scott Sheffield

Okay, next. What’s the next question?

Timothy Dove

We must to drop off. If there any questions?

Operator

Yes, we’ll take our next question from Phillips Johnston of Capital One.

Phillips Johnston - Capital One

Hey guys, thanks. In the southern Wolfcamp area you’re focusing on the higher return areas in the north, I’m just wondering if you can give us [indiscernible] of what percentage of your overall acreage position that area represents. And also if you can just discuss the differences in returns and that area versus the acreage in southern region?

Scott Sheffield

Yeah, Phillips, I just give you a feel for it, we’re probably making 60% to 70% returns in the north based on the area up there typically generating 5, 6, 700,000 barrel BOE and then south of course in some of the areas the very south it’s in the neighborhood of 400,000 BOE, so I’d say that’s why it splits probably two thirds of acreage is that acreage that we have sideway returns in the north.

Phillips Johnston - Capital One

Okay, and then south obviously about third of your wells this year plan for A, C and D of those three zones which is the most the de-risk at this point do you think?

Scott Sheffield

I think the A is the most de-risk in the southern Wolfcamp, we’re just now putting our first C well on production, we’re just now going to be producing our first D well.

Phillips Johnston - Capital One

Okay, thank you guys.

Operator

And our next question comes from Sven Del Pozzo of IHS.

Sven Del Pozzo – IHS

Yeah, just quickly, could you describe – walking me through thought process that allow you to eliminate the extra casing string in the Eagle Ford?

Scott Sheffield

I think if you look at it – if you look at ways to reduce cost at all times, I think there is being exactly the same thing lot of other operators done, and we’ve just been piggybacking on that, but basically it’s understanding and experience when it comes to port pressure and controlling midway. And we’re drilling in the deepest part of the basin on average so this is something we held off doing for sometime but as we got more understanding we think it’s pretty clear we can eliminate a string and we’ve been very successful in doing that. So I think we de-risk than 100% now.

Sven Del Pozzo – IHS

So is the lateral portion of the well shorter, but you’re getting similar well performance to one where the lateral longer?

Scott Sheffield

I mentioned in the call that our lateral links have increased actually pretty substantially and so we’re getting really quite excellent well performance actually better well performance than we ever had the couple exceeding the lateral plus are optimization campaign when it comes to other wells are completed, so actually the well are doing significantly better in combining those aspect.

Sven Del Pozzo – IHS

And is the upper Eagle Ford I guess over how much total acreage position, Eagle Ford is the upper Eagle Ford do you think is prospective?

Scott Sheffield

About 25%.

Sven Del Pozzo – IHS

Alright, thank you.

Operator

And that concludes today’s question and answer session. At this time I’ll turn the floor back over to Scott Sheffield.

Scott Sheffield

Again we appreciate everybody’s time, taking the time and effort to listen to our first quarter call, look forward to I’m talking to you on our second quarter call in August. Thank you.

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