Nov 2, 2017
Executives
Frank E. Hopkins - Pioneer Natural Resources Co.
Timothy L. Dove - Pioneer Natural Resources Co.
J.D. Hall - Pioneer Natural Resources Co.
Kenneth H. Sheffield, Jr.
- Pioneer Natural Resources Co. Richard P.
Dealy - Pioneer Natural Resources Co.
Analysts
David Kistler - Simmons/Piper Jaffray Arun Jayaram - JPMorgan Securities LLC Doug Leggate - Bank of America Merrill Lynch John A. Freeman - Raymond James & Associates, Inc.
Evan Calio - Morgan Stanley & Co. LLC Scott Hanold - RBC Capital Markets LLC Charles A.
Meade - Johnson Rice & Co. LLC Michael Anthony Hall - Heikkinen Energy Advisors LLC Brian Singer - Goldman Sachs & Co.
LLC
Operator
Welcome to the Pioneer Natural Resources Third Quarter Conference Call. Joining us today will be: Tim Dove, President and Chief Executive Officer; Joey Hall, Executive Vice President, Permian Operations; Ken Sheffield, Executive Vice President, Operations/Engineering/Facilities; Rich Dealy, Executive Vice President and Chief Financial Officer; and Frank Hopkins, Senior Vice President, 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 November 27, 2017.
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 two of the slide presentation and 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, Investor Relations, Frank Hopkins.
Please go ahead, sir.
Frank E. Hopkins - Pioneer Natural Resources Co.
Thanks, Jena. Good day, everyone, and thanks again this quarter for joining us.
I'm going to briefly review the agenda for today's call. Tim will be the first speaker.
He'll provide the financial and operating highlights for the third quarter of 2017, another strong quarter for Pioneer and our latest outlook for the remainder of the year. He'll also provide some thoughts post 2017 and some of the things we're looking at down the road.
After Tim concludes his remarks, Joey is going to review our continuing strong horizontal well performance in the Spraberry/Wolfcamp. He will also update you on drilling plans for the remainder of this year in the Spraberry/Wolfcamp area.
Ken will then discuss the excellent results we're seeing from our drilling program in the Eagle Ford Shale this year. And lastly, Rich is going to summarize the third quarter financials and he'll provide guidance for the fourth quarter.
After that, as always, we're going to open up the call for any questions that folks on the line may have. So with that, Tim, I'll turn the call over to you.
Timothy L. Dove - Pioneer Natural Resources Co.
Thanks, Frank. And first, a shout-out to all of our friends in Houston.
I know it was a tough third quarter there, everybody went through down there, but nonetheless, hopefully last night helps to vindicate at least a powerful positive spirit for the city. So congratulations for that.
Pioneer's third quarter results show that the company is executing at a very high level of efficiency. Our horizontal oil production is up substantially.
Our POPs were right on schedule for the quarter and our operating costs were down. And as you've seen, our Eagle Ford drilling program has been very successful thus far.
We had an excellent quarter from the standpoint of income generation. We had adjusted income of $80 million, realizing we have relatively low breakevens in our company.
And even at today's oil and gas prices, that's a substantial amount of income generation, considering where those commodity prices are, that represented about $0.48 per diluted share. As you'll recall, we preannounced production post the hurricanes and also our price realizations.
Those were released both on October 12. That said, this is somewhat old news as to where the third quarter production came in.
What's important is we did see a very dramatic increase in overall production, that's in terms of BOEs, even though it was negatively affected by the hurricane and third-party processing downtime in our West Panhandle facilities. In fact, production would've been at the top end of the range had it not been for these issues.
Importantly, oil production is up substantially. It's up about 10% overall in the third quarter compared to the second.
And in particular, if you look at the growth from our Permian Basin drilling operations, you can see very substantial increases in oil production growth of about 15% for the quarter. This goes to show that the campaign is, in fact, producing excellent results.
And this is not just growth for growth's sake, of course. These growth numbers are really based on strong returns and high capital efficiency.
A component of that efficiency is the fact that we've been able to continue to focus on production costs. They were down again this quarter, down to about $6.01 per BOE.
That's down compared to the second and also 2016's operating costs numbers. It's a product of the fact that our Spraberry/Wolfcamp horizontal wells show a very low-cost production.
And in fact, for this quarter, it was about $1.85 per BOE. Turning now to slide 4 and continuing with the highlights for the quarter.
Hedging continues to be an important part of our go-forward strategy and toward that end, we did add derivatives in the quarter, 59,000 barrels a day of oil and 83 million cubic feet a day of gas. Combination of three-way collars and swaps to the point where now, we have derivatives that cover over 80% of 2018's oil production forecast and over 35% of our gas.
So that puts us in a very good position going forward, protected against what might be possible downturns in commodity prices as we go forward. The balance sheet continues to look very strong with $2.1 billion of cash and liquid investments on hand.
And accordingly, we continue to have very low debt ratios as shown on slide 4. We've become a very significant player in world export markets and I think that will continue through time.
As shown in the slide, we exported 1.4 million barrels of WTI during the third quarter and expect that number to be 2.3 million barrels during this quarter. The last three cargoes interestingly have gone through various areas of the world, including South Korea and Japan as well as into Wales.
It's really quite possible, if you look at our numbers internally, that our export volumes could quadruple next year compared to this year. In fact, it's possible by the end of 2018, we would be exporting 100,000 barrels a day.
So this is going to be a bigger and bigger component of our plan going forward. I'd say more importantly though, with the Brent-WTI spread having widened to, let's say, $7 to $8 per barrel, our most recent sales have been accomplished at a premium to WTI of nearly $5.
And accordingly, those sales are just not moving oil, they're making substantial value-adds when compared to our alternatives for domestic sales. Really, we do need the exports to move all this incremental oil that's going to be coming out of the Permian Basin and we're making significant strides toward that end.
Turning now to slide 5. First of all, we reached a significant milestone this quarter.
We spudded our 1,000th horizontal well in the Spraberry/Wolfcamp trend in the third quarter. That's a fantastic result and we're way ahead, of course, from that standpoint in terms of gaining knowledge about how to properly drill and complete these wells having now done over 1,000.
As we've been discussing on the road and with many investors and analysts, we've been considering the acceleration of rigs that were planned for later in 2018 in order to improve our operational flexibility. And toward that end, we decided to pull the trigger on adding two rigs to improve our operational flexibility by adding to our drilled, but as yet uncompleted well count.
And what that will do, of course, is give us flexibility going forward. The DUCs that will be added in the first half of the year will then be resulting in the fact that we'll have production growth met just as we would have in the original plan later in 2018.
So what we're essentially doing is bringing these rigs in early. It doesn't really have much effect on the longer-term growth forecasts for 2018.
That does lead us to having 20 rigs in place in the Permian Basin, 16 of those being in the North. That will add to our capital needs for 2017.
We're adding a total of $50 million, one part of it being the addition of those two rigs and the other part related to the fact that we're using third-party frac fleets in the Eagle Ford shale and they've come in significantly higher in South Texas and it was in the plan. It is a fact that there's not much competition for fleets in South Texas.
And so that's where you see some inflationary effects. I wouldn't be surprised if we don't see that in the Permian as well.
It doesn't really affect us to the extent we're operating mostly our own fleets. We have been very successful this quarter in the implementation of the four-string casing design where it's necessary and it's probably today three-quarters of our wells.
That number will be reduced going forward. We did put our – put the number of wells planned on production, our POPs were 61 during the quarter.
And if you look at that, 59 were Version 3.0 completions that continue to have excellent results when compared to Version 2.0. And a couple of those wells were completed in the Jo Mill and they also show excellent results.
And our 3.0+ wells, although we've only done 12, really look good and Joey is going to show you some curves on all of these. But suffice it to say, our EUR's and our performance from wells is staggering in terms of its positive impact on production.
And we expect that to continue going forward. The POP number for the fourth quarter would be about 70.
That will get us to the 230 target that we've already put out in terms of the goal for 2017. Again, the returns are very strong, even based on $50 oil and $3 gas.
We still see 40% to 75% rates of return just from the drilling campaign and that has allocated capital for facilities needs as well. So I think the returns will stay exceedingly strong even going into 2018.
Turning now to slide six. I already mentioned earlier the outstanding results we've seen in the Eagle Ford campaign this year.
Recall that we're completing 20 wells. Nine of those were DUCs and 11 were new wells.
The objective was to drill longer laterals, have the wells be wider spaced than their earlier campaigns and have higher intensity completions, along the lines more of what we use in the Permian Basin to see if we could positively impact results. Returns look good.
I mean, they're still 30% to 40% even based on $3 gas and $50 oil themselves. But importantly, we've seen that these new wells that we've already put on, a couple of them were the new drills and nine were the DUCs in the last couple quarters.
They've basically 2X'd their prior – the prior campaign wells over the early part of their production. That's really encouraging.
It means that we may have uncovered a significant amount of value from this drilling campaign in terms of the future inventory wells to be drilled. A couple more wells have been POP'd here in early October, so we're just starting to see those results.
And the last seven are expected to be POP'd in November. So we'll have a lot more data for you as it relates to this on the fourth quarter call coming up in February.
We can give you a full recap of how those wells have done. In West Panhandle, this has already been explained from the standpoint of the October release, but we did have a fire at a third-party plant handling our processing volumes in the West Panhandle field.
This is a Sunray plant and we had to quickly redirect this gas. It took some work from the standpoint of plumbing and spending some money to get the gas redirected to another plant.
But suffice it to say, that's now been completed. The gas has been re-piped and now being processed at another facility in Spearman, Texas.
It's about 8,000 barrels of oil per day. We did lose production as a result of that.
That's part of the total 3,500 barrels a day of production, which we lost that impacted the third quarter in addition to the volumes that were attributable to the hurricane. Now turning to slide seven.
Our capital remains essentially the same, except for what I mentioned earlier, which is the accounting for the addition of the two rigs for the balance of this year in Permian and also the incremental completions cost in the Eagle Ford from third parties, such that the total is now estimated to be $2.75 billion for the year. Importantly, our cash flow is coming in roughly at $1.9 billion, I think that's likely conservative because it's based on $49, $50 going forward for the fourth quarter on oil today with prices at about $54, that $1.9 billion is likely conservative.
But nonetheless, I think we have a good wherewithal to enter 2018 with an exceptionally strong balance sheet after having completed this year's campaign. Turning to slide eight.
We continue to be on target to meet all of our growth goals, both for the fourth quarter and for all of this year, 2017. That's in terms of overall growth as well as oil growth.
And importantly, after we finish the fourth quarter, it will represent the completion of the first year in our march to produce the 1 million barrel plus BOE per day, basically in nine more years, and that would include 700,000 barrels a day of oil at that time and we'll have more on that in a couple slides. On slide nine then, the long-term goal, when it comes to that 10-year plan, is supported by the fact that Pioneer's acreage sits in essentially the best rock in one of the lowest breakeven oil price basins in the country.
And as shown in the graph here on slide nine, from sell-side research, you could see that the Permian Midland Basin breakeven oil price at roughly $24 per barrel is one of the lowest, if not, the lowest in North America. In essence, it's this benefit, the rock in the Midland Basin that gives us a distinct advantage in terms of returns.
Slide 10 then shows a different way to look at it. This is a snapshot of where Pioneer's breakeven is on that same third-party analysis as compared to many companies in the shale business in the U.S.
So when that data is broken down by company, you can see where our oil breakeven shakes out, again at the bottom of the list, compared to a long list of our E&P brethren. And it's this advantage that gives us confidence in our longer-term plan to execute based on those high returns.
Slide 11. As a result of the prior couple of slides, our 10-year vision remains very much intact, to produce that 1 million barrels plus really within the – in the next nine years or so, and it reflects really organic growth.
We don't have to go acquire acreage, we don't have to acquire leases to do that. We already have the locations basically sitting underneath our acreage that will allow us to grow at 15% plus.
But the important thing is, we're drilling very high rate of return wells and that's just a product of our low breakevens, among other things, as shown on the prior two slides, where we have very low cost and high returns and accordingly, low breakeven numbers. And those are very significant positives going forward from the standpoint of executing on this plan.
I think vertical integration and our technology enhancements, we've talked about in the past, are a very significant contributor to that plan going forward. Vertical integration of course is a big positive for us in the sense that it's going to protect us from inflationary moves going forward as well in terms of costs, notwithstanding the fact it helps us to execute at a high level as well.
A very important goal that we've been focused on of course is to get to a point where we are basically cash flow-neutral compared to our spending. This depends to a great extent, needless to say, on oil prices and in fact if you take a look at the modeling, our cash flow breakeven where we're spending an amount equal to our cash flow in 2020 would be based on a $50 oil price.
It's possible that could be achieved in 2018 depending upon what happens to the oil price. We would calculate that between $57 and $58, in that range, it would actually be cash flow breakeven for 2018.
So we're rapidly moving in that direction. It's just a matter of price as to when we get there.
Incidentally, related to that, the overall cash flow growth rate is higher than the overall production growth rate. It's about 20% per year.
It's due to the fact that we're drilling high cash flow and high rate of return wells that have significant margins owing to the fact they're mostly oil. We have accomplished a lot for 2018 in the derivatives program.
As I said, we feel like we're in good shape there and the balance sheet is in good position to support this plan going forward. We've always had a very heavy focus on improving corporate returns.
You should realize that we already have many, many metrics inside the company we use related to compensation that cover these exact points. For instance, internally related to our annual compensation programs, we have goals on production per share, on operating costs, on F&D, on reserve replacements and G&A, our balance sheet metrics.
And also ROE and ROCE and NAV per share, so we already have those all internally. And so the change we really plan to make only at this point going forward is to include a couple of those metrics, probably the growth per share metric and the return metric in our proxy filing in April of 2018.
But the fact is we're already utilizing those goals internally. So now it's just a matter of codifying that from the standpoint of our proxy filing, which you'll see us do in a form next year.
So to summarize, I think the third quarter was an excellent quarter for us. Our level of execution and performance that we pride ourselves on at PXD was reached for this quarter and I expect that to continue going forward as we prosecute over the next nine years as well.
And with that, I'm going to pass it over to Joey for his comments on the Spraberry/Wolfcamp results for the quarter.
J.D. Hall - Pioneer Natural Resources Co.
Thanks, Tim, and good morning to everybody. I'll be picking up on slide 12.
This is basically my punchline slide. We're now operating 20 rigs.
Version 3.0 remains the standard completion. I'm going to cover results on our larger completions here in just a second.
You can see our budgeted lateral lengths, well costs and EURs. Combine that with our low operating cost of $4 to $5 and that results in strong IRRs of 40% to 75% at 15.3%.
Moving to slide 13, here, we are showing results from 12 of our Version 3.0+ wells for four of our 3-well pads. All of these wells were POP'd in Q2, which is significant because now, we have four to six months' worth of production data.
All the tests continue to be promising; with longer production history we can now start to assess the economics of these wells compared to their 3.0 offsets and see where they will go for us in future programs. I do believe we're narrowing in on optimal water volumes and now we're trying to find the sweet spot on proppant combined with cluster spacing and stage lengths.
The only variables not noted on our slide is cluster spacing and stage length, which we believe is a second-tier lever impacting well performance. And just going around the page, if you look at our Lower Spraberry Shale, those were completed with 40-foot cluster spacing and 240-foot stage length.
The HUD and South University Wolfcamp Bs were completed with 30-foot cluster spacing and 150-foot stage length. And the Pembrook wells were completed with 20-foot cluster spacing and 100-foot stage length.
The reason I point that out is because it illustrates that with all these combinations, Pioneer's strong belief that one size definitely doesn't fit all and we continue to cater our completions to the areas and the zones with which we're drilling. Other points of interest on completions, we did successfully execute our 100% sliding sleeve well on a 3-well pad.
We shifted over 150 sleeves in each one of the three wells, so close to 500 sleeves shifted. The wells are on production and we are evaluating the results of those wells.
We're also interpreting the results of the stimulation phase of our fiber optic test and are now collecting data on that same well during the production phase and so we'll be evaluating those results here in the near future. So now, I'll be moving on to slide 14.
Just a real quick Jo Mill update. We did add two new wells in Q3 in the Northern part of our acreage.
The significance of these two wells is that they represent our first spacing test, so we're going to be looking forward to the results of those two wells. The other nine wells continued to exhibit strong performance.
Now moving on to slide 15 and my last slide. Strong production results, despite the impacts from Hurricane Harvey of 1,300 BOEs per day, is noted in the upper left, ending the quarter at 231,000 BOEs per day, a 9% increase over Q2.
As Tim mentioned, we did place 61 wells online, bringing our total to 160 for the year. And we are reiterating our expectation to grow production 30% to 32% over our 2016 production.
For Q4, we will continue to evaluate our completion optimization tests and determine how they fit into our 2018 program. And so bottom line overall, a great quarter for our Permian team and we are looking forward to a strong finish to 2017.
And with that, I'll now turn it over to Ken Sheffield, and he'll cover some impressive results from South Texas.
Kenneth H. Sheffield, Jr. - Pioneer Natural Resources Co.
Thank you, Joey, and good morning, everyone. Turning to slide 16, Pioneer's ramping up our 2017 drilling and completion program in the Eagle Ford.
The plan is to complete and POP 20 wells during the year, including nine DUCs drilled about a year ago and on the 11 new wells, testing design changes expected to significantly increase recovery. The design changes include longer laterals, increased well spacing, tighter counter cluster spacing and higher proppant concentrations.
The cumulative effect of the design changes are expected to yield EURs averaging 1.3 million barrels equivalent, with IRRs ranging from 30% to 40% on the new wells. We've seen excellent results from the wells we POP'd to date and results are summarized on the next slide.
Turning to slide 17. The upper left chart shows the 2017 program results compared to the most recently drilled Eagle Ford wells in 2015 and the early part of 2016.
Average cumulative production charted in red from the 9 DUCs POP'd in Q2 and Q3 is more than two times higher than prior program wells charted in blue. This is a result of more intense completions and longer laterals.
Average cumulative production charted in orange from the two new design wells is showing even stronger results. At the end of Q3, we have 11 of the 20 planned POPs online.
Nine new drills are expected to POP in 4Q, with two wells POP'd early in October. We are very pleased with the results to date, looking forward to closing out the remaining POPs and integrating these strong results into plans for the future.
I'll now turn it over to Rich Dealy to review financial results.
Richard P. Dealy - Pioneer Natural Resources Co.
Thanks, Ken. Good morning, and I'm going to start on slide 18, where we reported a net loss attributable to common stockholders of $23 million or $0.13 per diluted share.
It did include non-cash mark-to-market derivative losses of $103 million or $0.61 per diluted share. So as Tim mentioned, if you adjust for that, we had a really strong earnings for the quarter at $80 million or $0.48 per diluted share.
If you look at the middle of the page where we show Q3 guidance relative to our actual results, you'll see that we are within guidance or on the positive side of the guidance of all the items listed here. So overall, an exceptionally strong quarter for the company.
Turning to slide 19 and looking at price realizations. As you can see, oil prices were up 1% quarter-over-quarter.
NGL prices were up 12%, most of that coming from both propane and butane prices and ethane prices to a smaller extent. And so really seeing NGL pricing increase during the quarter helped our realizations there.
Gas prices were down 2% to $2.58 per MCF. These results do exclude $29 million of cash receipts from our hedging activity that came in during the quarter.
If you look at the bottom of the slide, you can see the impact of those to our pricing and if you include those hedging results. Turning to slide 20, looking at production cost per BOE.
You see that production costs in total were down 3% quarter-over-quarter. Excluding taxes, production costs were down also 3% versus Q2, sorry, and 11% versus 2016.
The decline is primarily due to our increasing production from our lower-cost horizontal Spraberry/Wolfcamp wells. And if you look at over the past two years, production costs, excluding taxes, have averaged $2.25 per BOE on our horizontal Spraberry/Wolfcamp production.
The other item of note here is workover costs. They were higher during the quarter, primarily associated with vertical well activity and really as a result of higher oil prices and improving economics, we were able to repair those wells and put them back on to production.
Turning to slide 21, looking at our liquidity position, as Tim mentioned, we continue to have an excellent balance sheet and strong liquidity. If you look at the end of the quarter, we had net debt of $600 million, reflecting gross debt of $2.7 billion and cash on hand of $2.1 billion, completely unutilized credit facility at $1.5 billion of capacity there.
And our debt ratios, as Tim mentioned earlier, are great. If you look at the maturity schedule, in the middle of the page there, you can see our next bond maturity is in 2018 and our current plan is to pay those bonds off with cash on hand in May of next year.
Turning to slide 22 and really switching gears and looking at the fourth quarter guidance, you'll see the daily production, an increase from where we were this quarter, up to 292,000 BOEs to 302,000 BOEs per day. The rest of the items on this page are consistent with prior quarters, other than two.
I'll note the production costs with our continuing decline in production cost. We did lower that range to $7.50 to $9.50 per BOE, and we also lowered our DD&A rate guidance range from $13.50 to $15.50 per BOE, really reflecting the additional proved reserves that we're adding from our successful drilling program.
So with that, I'll stop there, Jena, and we'll open up the call for questions.
Operator
Thank you. And we'll take our first question from Dave Kistler of Simmons/Piper Jaffray.
David Kistler - Simmons/Piper Jaffray
Good morning, guys.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, Dave.
David Kistler - Simmons/Piper Jaffray
Picking up a little bit on your comment of cash flow neutrality at certain prices, I think you were saying $57 to $58, we get to cash flow-neutral. In the event, knowing you're well hedged, but with collars, in the event that prices did hit those levels, would that be the goal to be cash flow-neutral?
Or would you redeploy to accelerate activity?
Timothy L. Dove - Pioneer Natural Resources Co.
Dave, as you know, we've been talking about this for some time when we rolled out the 10-year plan that one of our objectives is kind of keep the RPMs steady from the standpoint of our operational goals. And I think if we really hit $57 to $58, we probably would just be the beneficiary of not overspending at all in 2018 and we would probably keep it at that because I think you can see that we're running at a high degree of efficiency.
And adding RPMs, I think, would probably be inefficient from the standpoint of diminishing returns based on – we expect to see inflation in some areas. And as a result, I think we will stay pat with our plan for 2018.
David Kistler - Simmons/Piper Jaffray
Okay, appreciate that. And kind of thinking about the efficiency comment you just made, adding these incremental rigs a little bit earlier, building up a little larger POP inventory.
With that kind of structure in place, are we looking at getting back to kind of 260 POPs a year? Just trying to get a sense for whether or not that's accelerating above and beyond that potentially for 2018.
Timothy L. Dove - Pioneer Natural Resources Co.
Yeah, I think the current work we're doing, and of course, this is relatively preliminary from the standpoint of the fact we haven't gotten very far yet in terms of our 2018 capital budgeting, in terms of the dealings with the board and other matters. But current thought would be POPing significantly in excess of 230 wells next year.
Probably the range is 250 to 275 wells. Also in relation to bringing on the rigs earlier, we also will be building about a 20 DUC count build and that's just, as I mentioned earlier, related to improving our operational flexibility.
So I think that's probably in the neighborhood of where the numbers will come out for 2018.
David Kistler - Simmons/Piper Jaffray
And just one little follow-up on that, I apologize. But with that DUC build, really less – it sounds like less oriented on flexibility to accelerate activity, more oriented on ensuring seamless delivery of POPs to kind of get a more linear production cycle versus a kind of lumpy one that we've seen in the past?
Timothy L. Dove - Pioneer Natural Resources Co.
I think that's right, Dave. If you look at, I mean, needless to say, the rigs eventually, when you get to the second half of 2018, do exactly what they would've done had we added them then, which is add production in the second half of 2018 and into 2019.
But for the time being, the way they should be thought of is increasing our utilization rates on our frac fleets, basically affecting, in a positive way, our ability to make sure there are no delays. And in that sense, what we're doing is adding operational flexibility.
So I would really say it's a culmination of the two, the early-stage being operational flexibility, having the number one priority, and secondly, it will then contribute to production growth in the second half of the year and into 2019.
David Kistler - Simmons/Piper Jaffray
Okay. Appreciate the color guys.
Thanks so much.
Timothy L. Dove - Pioneer Natural Resources Co.
You bet.
Operator
And our next question comes from Arun Jayaram from JPMorgan.
Arun Jayaram - JPMorgan Securities LLC
Yeah. Good morning.
Tim, I was wondering if you could go through some of the objectives of the Eagle Ford delineation program and also just thoughts on the Jo Mill, could fit into the future plans from a development standpoint.
Timothy L. Dove - Pioneer Natural Resources Co.
Yeah, I think, first of all, on the Eagle Ford, as you know, one of our main objectives was to make sure that we could actually get back to drilling economic wells. What I mean by economic is more economic than we've determined that the 2015 and 2016 campaign had delivered.
We really got too far down-spaced, we felt like. And notwithstanding that, we are also, on a relative basis, completing those wells on shorter laterals with the old-style Eagle Ford frac, which we've now proven really was not as successful as we would expect when we put a Permian-style frac on that.
So we really needed to make sure that we could understand how it is that we can improve the economics of wells. The Eagle Ford, as you know, is an area where we produce a third natural gas and a third NGLs, in addition to a third condensate.
So it has to be an area we needed to improve the economics of drilling, and I think we've done exactly that. So it definitely gives us a view towards the value of our inventory of drilling locations clearly improving.
On the Jo Mill, the Jo Mill has a very significant place going forward when it comes to our development planning. We've seen presentations internally, where over the next nine years, we'll be drilling quite a large number of Jo Mill locations as it relates to that plan and because these results looks so strong, I'm very encouraged by that.
Arun Jayaram - JPMorgan Securities LLC
Great. And just my follow-up.
This year, Tim, you're doing, I believe, a 15-well program with the Version 3.0+. I was wondering if you can comment on how the costs look like relative to 3.0 and how you're thinking about moving the program, shifting towards perhaps more Version 3.0+ completions in 2018 and beyond.
Timothy L. Dove - Pioneer Natural Resources Co.
Sure. Well, first of all, if you look at the costs associated with the 3.0+ as compared to Version 3, you will add – depending upon how much you increase the sand utilization, between $500,000 and, let's say, $750,000 per well.
So from that standpoint, you're looking at something that's probably not even 10% of the well cost. So from that standpoint also, when you look at the 3.0+ results, they look really outstanding and clearly well in excess of 5% or 10% (34:34) improvement.
So I think what's going to prove out is that the 3.0+ may eventually become a standard if this were to bear out. That said, we're not going to make any decisions based on 15 wells and for that matter, a relatively short history on those 15 wells.
So we're evaluating right now how many wells to complete utilizing 3.0+ for 2018. And then as has been our case through time, if you remember, we went from 1.0 to 2.0 to 3.0, in each case, taking a significant amount of time to make sure we knew what we're accomplishing when it came to improving economics.
We're going to do the same thing here. So we need some time to see more 3.0+ wells.
It wouldn't surprise me that 3.0+ would become the standard, but we need to get some more data before we can go there.
Arun Jayaram - JPMorgan Securities LLC
Great. Thanks for your comments.
Operator
Our next question comes from Doug Leggate of Bank of America.
Doug Leggate - Bank of America Merrill Lynch
Thanks. Good morning, everybody.
Morning, Tim.
Timothy L. Dove - Pioneer Natural Resources Co.
Morning, Doug.
Doug Leggate - Bank of America Merrill Lynch
Tim, can I – maybe it's Joey wants to take this one, but if I can go back to slide 13, I just wonder if you just revisit your comments about the changes in well design that you were talking about. Did I hear you correct that you're running 150-stage sliding sleeve designs in these wells?
How many have you done? Are you seeing significant differences versus the prior design?
Just walk us through what the thought process there, please.
J.D. Hall - Pioneer Natural Resources Co.
Sure. To clarify, we've only done one pad of three wells, each one had 156 sliding sleeves.
The most important thing to back up on is why we did the test. This was in Lower Spraberry Shale and we did it for two objectives.
Number one, whenever you're in the shallower, lower pressured zones, it creates some – a little bit less efficient on the drill outside and makes it more difficult to drill your plugs out. So obviously, if you have sliding sleeves, you eliminate all plugs and that takes care of that particular issue.
But the other thing is if you can figure out how to do it efficiently, you can get more clusters per the entire wellbore. The only challenge with it right now is it's relatively new technology.
So the operational piece of it's kind of slow. But for us, the most important piece is seeing how the production comes out because whenever you do a sliding sleeve, in essence, you're stimulating one cluster at a time instead of five or six clusters at a time.
So this whole debate that people sometimes get into on how effectively are you stimulating in each individual cluster when there's multiple clusters per stage, using the sliding sleeves eliminates that debate and you effectively get 100% of your clusters stimulated because you're only stimulating one cluster at a time. So we see this as a long-term strategy that could expand.
There's also some new technologies evolving regarding interventionless sliding sleeves, where you don't have to use coil tubing, because that's one of the challenges associated with these sliding sleeves. So for us, this is more determining, one, how does the individual cluster stimulation work.
Operationally, we think there's room for improvement. But we see this as something we wanted to test to see how it fits into our long-term strategy.
Doug Leggate - Bank of America Merrill Lynch
I realize as a test, the cost may not be comparable, but just for reference, how did the production compare to what you're describing as the Version 3 and similarly with the costs?
J.D. Hall - Pioneer Natural Resources Co.
So it's very early. We just turned these wells on in the last month or month and a half, so it's too early to tell.
I will tell you that I think preliminary indications are that – and again, very early, that they are – appear to be performing comparable to our 3.0+ wells. But again, it's very early.
One of the things that we've learned with these higher water volumes is that it takes just a little bit longer for us to understand the full performance of the wells and so it's really too early to make a conclusion.
Doug Leggate - Bank of America Merrill Lynch
Okay, I appreciate that. I just had a couple of quick follow-ups, if I may.
Tim, the Version 3.0+, is the guidance that you've given in terms of the breakeven for next year, does that assume the Version 3.0 or the Version 3.0+?
Timothy L. Dove - Pioneer Natural Resources Co.
Everything we're doing right now, Doug, is defaulted to 3.0.
Doug Leggate - Bank of America Merrill Lynch
Okay. And last one from me is, really, just going back to the earlier question about the Eagle Ford and, I guess, the general portfolio outside of the Permian, still a decline drag on the very strong growth from the Spraberry/Wolfcamp program.
What is the longer term prognosis for the ex-Permian assets? And I'll leave it there.
Thanks.
Timothy L. Dove - Pioneer Natural Resources Co.
Thanks, Doug. Yeah, I think what we're going to be doing is evaluating all of these wells and their impact on the inventory.
And if you look at what we've seen so far, it's been dramatically positive. We've been able to essentially 2x the prior campaign's drilling results.
And I take it as some encouragement that this inventory is actually showing signs of really significant recovery when it comes to economics. Of course, we also have to weigh how those wells compare on a relative return basis after we get all the data with how the Permian campaign is shaping up in terms of returns.
I think that will be something we evaluate as we see the fullness of the program completed here with these seven wells, putting those on production in November and watching their production. We'll make some assessments as to that question as we get into the early part of next year.
Doug Leggate - Bank of America Merrill Lynch
Do you plan any capital in the Eagle Ford in 2018?
Timothy L. Dove - Pioneer Natural Resources Co.
Well, that's the question we're addressing. The question is how much capital will we spend based on how the well results appear?
And that's just a part of our evaluations for the whole budget for 2018.
Doug Leggate - Bank of America Merrill Lynch
Thanks a lot guys.
Timothy L. Dove - Pioneer Natural Resources Co.
You bet.
Operator
Our next question comes from John Freeman of Raymond James.
John A. Freeman - Raymond James & Associates, Inc.
Good morning, guys.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, John.
John A. Freeman - Raymond James & Associates, Inc.
When looking at the Eagle Ford, I realize you slightly lowered sort of the IRRs given the higher cost, but it looks like you're still using the same 1.3 MMBOE EUR guidance. And when I look at the update we had last quarter and you were looking at kind of a 20% productivity uplift on these new completions and now, it's basically doubling.
It's like the longer these wells are online, it looks like the outperformance is getting meaningfully wider. Just sort of the thoughts on maybe when you might reevaluate the type curves that you all were using.
Frank E. Hopkins - Pioneer Natural Resources Co.
Yeah, hey, John. This is Frank.
I think when you look at it, you're spot on to what we're seeing. I think, though, as Tim referred to and Ken, when they were talking about it, we just don't have a lot of data on these wells yet.
And matter of fact, we have some that we're just about to POP here, as Ken mentioned. So I think over time, those numbers could go up.
But for the time being, we just assume the 1.3 MMBOE EUR.
John A. Freeman - Raymond James & Associates, Inc.
Okay. And then just my follow-up, sticking with the Eagle Ford, obviously, on the well costs, you all mentioned it was mainly due to these – the third-party frac fleets just where the prices went.
I'm just curious if all this would have you all potentially consider, reconsider potentially using or activating, starting up additional of your own fleets just given where the costs are of if that's still kind of off the table.
Timothy L. Dove - Pioneer Natural Resources Co.
Certainly, I think we can consider that. I mean, realizing today, we operate, among our whole set of fleets, depending upon the day, six or seven fleets.
That said, we have eight to – fleet number eight and nine, I should say, which are today not being utilized and need to be refurbed. So any decision along those lines would await refurbishing those fleets, which is probably going to be a 2018 project, so it's certainly not in the short term.
John A. Freeman - Raymond James & Associates, Inc.
Great. Thanks guys.
Operator
Our next question comes from Evan Calio of Morgan Stanley.
Evan Calio - Morgan Stanley & Co. LLC
Hey, good morning guys.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, Evan.
Evan Calio - Morgan Stanley & Co. LLC
Yeah, you mentioned 250 to 275 POPs, wells POPs in 2018. Should they be back end-loaded like 2017 and any CapEx range there?
Also, any downside to your $300 million infrastructure spend with Brady mine behind you and infrastructure spend as well behind?
Timothy L. Dove - Pioneer Natural Resources Co.
I think if you look at the POP count, this is more of an estimate of the overall number. We have not gotten yet into the granularity of exactly how they're going to be mapped out in the year.
And of course, that's a complicated matter related to when the rigs are there, how the pads are arranged in terms of the order of completion. So we'll certainly have more color on that when we put out results for the fourth quarter on our views towards 2018.
In fact, we'll probably give you a pretty detailed POP schedule at that time. So I think when you look at that, the number we give you right now is just more of a top-down consideration of where we're trying to land the thing.
So I think from that standpoint, you can just kind of use it as a top-down number, and for the time being, just assume those are flat.
Evan Calio - Morgan Stanley & Co. LLC
And the midstream?
Timothy L. Dove - Pioneer Natural Resources Co.
Yes. If you look at the additional costs right now, first of all, we are postponing the expansion of our Brady plant, that's been well publicized as we evaluate the West Texas sand situation and – as an alternative to sand supply.
So we don't have to expand the Brady plant today. We're evaluating its competitiveness from a go-forward standpoint and expansion versus these other alternatives.
That said, we are going to need to be spending money on third-party processing. Targa has two new plants planned for 2018, one coming in place in March and the other one in, roughly around September.
Those will demand capital as well. We have our regular infrastructure needs of course going forward and compression in the field with Targa.
But as I'd say, from the standpoint of other items, they're not really anything material other than the fact that as we already have said, our water systems will capture essentially the same amount of capital in 2018 as it did in 2017. So roughly flat at about $150 million or so compared to 2017.
That's going to be the material numbers when it comes to our overall other expenditures.
Evan Calio - Morgan Stanley & Co. LLC
Great. Maybe second is a bigger picture question.
And the producer question du jour pits growth versus return and corporate strategy where it really comes down to asset portfolio, managing risk and maximizing value. I know you have a deeper inventory than most of your peers and that's what allows you this 10-year outlook of high growth at low price.
Yet just to harmonize where relatively more mature portfolios stack, when you look at the life of the asset, post 1 million barrels growth, I mean, do you see a multi-decade plateau where cash distribution has become a defining characteristic of the asset? Maybe just your thoughts there on returns versus growth and maximizing shareholder value longer term is appreciated.
Thanks.
Timothy L. Dove - Pioneer Natural Resources Co.
As I mentioned earlier, we're very heavily focused on getting to free cash flow generation actually. Our first goal is to get neutrality and then we'll work on free cash flow generation.
So that's certainly one of our goals. But it's a little bit hard to forecast 10 – after 10 years, we're working hard in the next nine, but years 11 through 20, we have to get to work on, I guess, is what I'd say.
But needless to say, we're going to be drilling probably 6,000 wells in our – over this whole 10-year period, including this year. And as you recall, our information, we've discussed over the years, has us with a 20,000-well inventory.
Internally, we show up to 35,000 locations depending upon price. And so from that standpoint, we can continue to move ahead from the standpoint of a growth profile.
You have to decide at what point you want to limit the number of rigs you want to put to work when it becomes really a very large number operationally and from an efficiency standpoint. But certainly, in our case, we can show growth over the next nine years, as I said, with that issue just so – because of the inventory you mentioned.
Others who don't have maybe the inventory or the set of economic wells to drill might not be in that situation. So it could lead to certain companies like ourselves and some of the companies with that larger profile continuing to grow, probably albeit at a lower rate in years 11 through 20.
But you may have an overall plateauing from the Permian Basin at that point simply because others might not be in that situation. Now that said, Permian Basin production at that time will be multiples of what it is today.
So it's going to lead the United States in a very strong position from the standpoint of oil exports and their importance in terms of the global energy picture.
Evan Calio - Morgan Stanley & Co. LLC
Right, very differentiated long-term outlook. But thanks for your comments.
Timothy L. Dove - Pioneer Natural Resources Co.
You bet.
Operator
Our next question comes from Scott Hanold of RBC Capital Markets.
Scott Hanold - RBC Capital Markets LLC
Yeah. Hi.
Thanks. Good morning.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, Scott.
Scott Hanold - RBC Capital Markets LLC
Hi. If I could maybe add on to that the last line of questioning.
And with such a large inventory, and maybe this is a little bit of heresy to say this for a publicly operated company with such a long inventory of good stuff, but what type of consideration have you all made to the inventory that's out 10, 15 years if the market right now makes sense to actually harvest some of that to other buyers who are willing to pay for it and put it to work right away?
Timothy L. Dove - Pioneer Natural Resources Co.
I think that's a great question and it's something we consider all the time as we should because the fact is we have many, many locations just, as I just said, that are – probably won't be drilled for a decade or more. But that said, we're reticent to do anything in particular for a couple of reasons today.
One is the fact that after some recent sales we've done in the Permian Basin, essentially all we have is core of the core property, what we would call Tier 1 property. And accordingly, it's really the crown jewels of the United States oil and gas business, particularly the oil business, the oil shale business.
So you've got to be really careful in consideration of that. The second point is, we haven't even drilled some of the location – some of the zones yet.
Realizing coming up, we are going to be drilling our first Clearfork well horizontally in Midland County. And as we've also said, we have not even drilled the Wolfcamp C well ourselves.
Fortunately, Parsley has done a great job drilling Wolfcamp Cs and we can let them delineate that. It proves up 900 to 1,000 Pioneer locations by doing so.
In addition, we haven't drilled some of the deeper locations – deeper zones. That would be, for example, the Woodford, the Barnett and so on that are productive, we believe, from the standpoint of oil in the Midland Basin as well just as in some areas, you see them productive in the Delaware Basin.
Haven't drilled a well there. It's deeper drilling, so it – and it's probably more gassy.
So in the seriatim of locations, it may not be at the top of the list. All that said, since we haven't drilled some of these locations, we don't want to put ourselves in a position where we convey assets or interests or zones where we don't even know what it is we own.
So that occurs to me to be the reason to hold off on anything significant along the lines of what you're saying. That also said, technology changes have proven to be the key to where this basin is today.
And I don't think we're done with technology change. And to the extent that we were to convey interest in assets or zones that otherwise would be unlocked as to their potential due to technology change, we would be remiss if we didn't see that technology change play out through time.
So although I think the idea is very elegant and I think it actually makes sense if we really needed capital, that's not really the situation we're in as we go towards a free cash flow-neutral or a free cash flow-generating model. So it's something that's top of mind, but not necessarily front-burner, let's put it that way.
Scott Hanold - RBC Capital Markets LLC
I appreciate the response. And just so I understand one comment you made within that response, is there obviously the potential to maybe parse out a zone over time as you prove it up and would like to harvest some of the cash – harvest cash from an asset?
Timothy L. Dove - Pioneer Natural Resources Co.
Yes, I think a zone sale is a possibility. I mean, in essence, we've really done that in the South where our partners now, Sinochem owns the Wolfcamp and below and we continue to own the upper zones.
That said, if you were to convey such a zone to another party that's going to come in and drill on our same footprint, that causes other issues, right? In other words, bumping into each other.
It's also a situation you bring someone in and drill the same zones underneath areas where you're drilling other zones, you have competition for the same services. It theoretically is an inflationary effect you might get out of that.
So that's certainly one of the alternatives, but it's not clear to me that it's without some peril.
Scott Hanold - RBC Capital Markets LLC
Okay. Okay, that's great.
And then as a follow-up, I think you'd mentioned that right now, you're doing about 75% four-string. And could you just give us an update on some of the recent progress there?
How fast those wells are getting down if you're seeing some improvement as you do it a little bit more? And what could that percentage look like in 2018?
Timothy L. Dove - Pioneer Natural Resources Co.
Yes, okay. I will let Joey answer that question, Scott.
J.D. Hall - Pioneer Natural Resources Co.
Yeah, Scott, the four-string wells are going well. We've recently had some completed in as little as 22 days.
As you see in our – in the slides, some of them are up to 30 days. But now that we've hit our rhythm with that design, we can continue to work to drive those durations down.
When you look into 2018, as Tim alluded to earlier, we're still working through the details of what the total portfolio mix is. I don't think it's a simple 75%-25% like we've communicated in the past.
My expectation would be that going forward, you would start to see that go down based on two things. Number one, just the portfolio of wells as we drill more Lower Spraberry Shale and Jo Mill and even some Wolfcamp As that may give us the benefit of being able to do some – go back to some three-string in areas where we're doing four-string.
So our hope is to continue to progress the four-string, but also look for opportunity to go back to the three-string wherever we can.
Scott Hanold - RBC Capital Markets LLC
Appreciate it. Thanks.
Operator
And our next question comes from Charles Meade of Johnson Rice.
Charles A. Meade - Johnson Rice & Co. LLC
Good morning, Tim, to you and your whole team there.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, Charles.
Charles A. Meade - Johnson Rice & Co. LLC
I wanted to, if we could go back to that slide 13, which I thought had a lot of interesting stuff in it, and explore maybe the – one of the suggestions perhaps that that slide gives about the variability within this Version 3.0 completion design. As I look at it, it looks like if you go to the higher end of that, of the Version 3.0+, on the Pembroke, on the Pembroke pad, those results actually don't look like they have as much uplift as the lower end of that 3.0+ intensity with the 50 barrels and the 3,000 pounds per foot.
So I wonder if you could kind of share what your preliminary thoughts in there and perhaps it dovetails to what Joey said in the prepared comments that you think you found the sweet spot on the barrels of water, but perhaps not on the other parameters.
J.D. Hall - Pioneer Natural Resources Co.
Yes, Charles, so one of the things to keep in mind if you look at that Pembroke test is that that's 100-barrel per foot test. Two things that should be noteworthy is number one, just by the fact that we put 100 barrels per foot in, it takes a long time for these wells to clean up.
And in – particularly, in the Pembroke wells, even whenever we do a more standard completion, for whatever reason, that particular area produces water for a long time before you even start to cut oil. So not predicting, but just telling you that by the nature of the completion and by the nature of the area, it's just going to take a little bit more time for us to understand what that curve looks like.
And as you can see, we've only got 120 days' worth versus some of these others that are up to 180 days. So let's just wait and see how that plays out.
The other thing that you pointed out, and I think it's very noteworthy going back to the comments that I made is, we really do think we're starting to dial in on the water volumes. The question we're asking ourselves now is once you get that water volume dialed in, what is the optimal amount of sand that you can deliver with that amount of water?
Because we all know that if you can get those two things combined perfectly, then you've gotten there. If you go back to 2014, we actually tried that in the opposite fashion one time with not very good results, where we thought we knew what the optimum amount of sand to be delivered was and we tried to reduce the amount of water.
We're actually going in reverse now. We know and we believe we know what the right amount of water is and now, we're trying to maximize our sand.
So that's our mindset on this going forward.
Charles A. Meade - Johnson Rice & Co. LLC
That's helpful, in fact, Joey. And I really appreciate those, I guess, unseen variables there.
And then Tim, perhaps a question back for you. When we talk about the – or when we kind of look at the impact of accelerating these two rig adds, can you give us an idea kind of on a Spraberry/Wolfcamp program-wide basis, how many drilled, uncomplete wells in inventory were you looking at, say, in 2Q of this year?
So kind of your work-in-process inventory and what kind of level do you think – do you expect you're going to get to on a program-wide basis maybe in the midpoint of the year next year that's going to allow you to be more efficient and avoid those stumbles?
Timothy L. Dove - Pioneer Natural Resources Co.
That's a great question, Charles, and that's right on point with what we're trying to achieve. First of all, we run a very tight ship – and to give you an idea what I mean by that is if you look at the industry today in Permian, there's 2,400 drilled but uncompleted wells.
That's 7.5 wells per rig. Today, if you look at, let's say, 2017 numbers, we have generally been 15 to 20 DUCs at any given time for 17 or 18 rigs.
In other words, one well per rig. That just goes to show you how tightly run this business has been.
That's a tremendously efficient operation. However, it also has the potential to be disruptive if there's any kind of delays and that's certainly the thing we're trying to avoid here.
By adding 20 DUCs or so, which is kind of the number we would expect to add as a result of cranking up a couple of our other rigs, we then get up to, let's say, a range of, let's just say, 35 to 40 DUCs. That's the sweet spot because we're going to have seven or eight completion units out there, frac fleets, three-well pads and that's kind of the number you need to make sure that you have always an option to go to another well to complete it if you have a delay on a rig or what have you.
So it's that kind of a number we're talking about. That said, it only gets us to about two wells per rig, which is way more efficient than the rest of the industry.
But we're giving ourselves a little slack basically from an operational flexibility standpoint.
Charles A. Meade - Johnson Rice & Co. LLC
That makes sense and it's helpful detail. Thank you, Tim.
Timothy L. Dove - Pioneer Natural Resources Co.
You bet.
Operator
Our next question comes from Michael Hall of Heikkinen Energy Advisors.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
Thanks. Good morning.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, Michael.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
I guess I wanted to maybe come back a little bit on the question around potential efficiency gains from the Version 3.0 wells. To the extent those continue to support incremental use and you further the deployment of those new designs in 2018 and beyond, as you look at it, is it something that could be material enough from a capital efficiency standpoint to pull that breakeven timeframe forward?
And if so, how far forward do you think it could...?
Timothy L. Dove - Pioneer Natural Resources Co.
Well, I think that's right. Anything that we do to improve our margins, by definition, brings our cash flow neutrality date forward and that's exactly what would happen and has happened incidentally as we've gone from 1.0 to 3.0.
If we look at going to 3.0+, it would have that same impact. So if we end up defaulting to 3.0+ at a later date, let's say, into 2018, and that in effect adds, what I mentioned before, which is somewhere in the neighborhood of 500,000 to 700,000 per well, but you get this really significant kick in EURs and early production.
All of a sudden, you've incremented our growth rate, you've incremented the margins of the company. And in doing both of those, you accelerate your cash breakeven neutrality day significantly.
So that's exactly what the results should be, to the extent we went that direction.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
Okay. And have you attempted to maybe estimate what sort of timeframe impact that could have at this point yet?
Or is that premature?
Timothy L. Dove - Pioneer Natural Resources Co.
That's too early. Like we mentioned earlier, with 15 wells, we're not doing much as to forward forecasting.
We want to see more data, but there will be a time and place when we can actually give you those level of details.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
Fair enough, look forward to it. And then I guess, on the remaining parts of the portfolio, you gave us the kind of 2017 expected declines on the Eagle Ford, or updated that number.
I guess, how would you think about the declines on that business as well as the Raton, Panhandle in 2018? How should we kind of handicap those declines at this point?
Timothy L. Dove - Pioneer Natural Resources Co.
Well, I think you already have the Eagle Ford number in there. I think you can actually look back at our materials and we have information on production from all the areas as to each quarter over the last couple of years or so.
I'm referring specifically to slide 24. And if you look there, you can see Raton basically has been pretty flat.
I mean, it's 100% methane, but you can see each of the last three quarters, it's produced within 1 million cubic feet a day of the prior quarter, so it's very flat. West Panhandle is hard to assess simply because of the choppiness that's come out of this plant operation business we discussed earlier.
But it generally, if you look back through time, has exhibited roughly about a 10% decline rate.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
Okay. And then the Eagle Ford though, that 35% is pretty fair going forward as well?
That doesn't slow down at all?
Timothy L. Dove - Pioneer Natural Resources Co.
It's obviously a product of how much you drill, but that's correct. I mean, that's the basic fundamental decline rate.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
Okay. And then I guess, last one on my end would just be on the corporate return front, I guess, we have you this year at a kind of low single-digit type ROCE.
How much can that improve, would you think, as you look over the next few years towards that breakeven timeframe in 2020? With the current plan in a sort of $50 world, do you all have a view on how that looks over time?
Timothy L. Dove - Pioneer Natural Resources Co.
I'll let Rich answer that one, Michael.
Richard P. Dealy - Pioneer Natural Resources Co.
Yeah, I think when you look at the modeling on it and the returns these wells are generating over the next four or five years, that will go into double-digit range. So you look at it adding a couple percent per year based on a low base we're starting because of our high historical cost basis and not cost basis, but the depletion we've got rates in the Permian, but we should see pretty significant improvement, given the high rates of return these wells are generating over the next four or five years.
Timothy L. Dove - Pioneer Natural Resources Co.
And that's basically a $50, $55 casing...
Richard P. Dealy - Pioneer Natural Resources Co.
Yeah. That's right.
Timothy L. Dove - Pioneer Natural Resources Co.
Yeah.
Michael Anthony Hall - Heikkinen Energy Advisors LLC
Perfect. That's super-helpful.
Appreciate it. Thanks guys.
Operator
And our next question comes from Brian Singer of Goldman Sachs.
Brian Singer - Goldman Sachs & Co. LLC
Thank you. Good morning.
Timothy L. Dove - Pioneer Natural Resources Co.
Hi, Brian.
Brian Singer - Goldman Sachs & Co. LLC
Wanted to follow up on a couple points from your comments. First on the management incentives, I think you mentioned that you already have a lot of the management incentives geared towards corporate returns and per-share growth.
Can you just add any more color on whether any of the incentives internally or the weighting towards those incentives are changing or if it is simply a publication and a proxy of what's already in existence today?
Timothy L. Dove - Pioneer Natural Resources Co.
Yeah, that's a great question. Internally, of course, we look at every variable.
And some of them are intertwined, right? It depends on how – your finding cost ends up touching your DD&A rates and so on.
But the fact is – and actually – and your capital spending affects your debt numbers as well. So a lot of these goals are intertwined.
But as you -if you look at our incentives, we look at all those every year. The one thing we'll have to do when it comes to a proxy is we put a return metric in the proxy which we do not have today.
We will revamp the weightings in the proxy. But that's as yet undefined because we haven't had that resolved yet with our Compensation and Leadership Development Committee, which will be a topic at the November Board meeting.
But by definition of adding a return metric in there, we will be revamping the percentages.
Brian Singer - Goldman Sachs & Co. LLC
Great. Thank you.
And then my follow-up is back to the casing and the 75% of wells currently using the four-string and that number falling. You highlighted the Lower Spraberry and Jo Mill is taking a greater weighting.
I just wanted to also see if there was any shifts in the weighting towards the Southern Wolfcamp area or whether it was just simply shallower zones within Midland and Martin County?
J.D. Hall - Pioneer Natural Resources Co.
Yeah, Brian, we don't see any change in the Southern acreage. We see that's still going forward as 100% three-string.
Brian Singer - Goldman Sachs & Co. LLC
And also, are you changing your shift of POP mix or number of wells that you're drilling in the Southern area?
J.D. Hall - Pioneer Natural Resources Co.
No, we still look -- we still are planning to run four rigs in the Southern acreage.
Brian Singer - Goldman Sachs & Co. LLC
Great. Thank you.
Timothy L. Dove - Pioneer Natural Resources Co.
Thanks, Brian.
Operator
And that concludes today's question-and-answer session. At this time, we will turn the call back to the speakers for any additional or closing remarks.
Frank E. Hopkins - Pioneer Natural Resources Co.
Thanks everybody for being on the call. We appreciate it and we look forward to speaking with you on the road or at the very least in February.
And from all of us at Pioneer, we hope you all have a great set of holidays and thanks for participating on the call.
Operator
This concludes today's call. Thank you for your participation.
You may now disconnect.