先鋒自然資源 (PXD) 2017 Q3 法說會逐字稿

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 and 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 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 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.

Thanks, Gina. 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.

Thanks, Frank. And first, a shout-out to all our friends in Houston. I know it was a tough third quarter that 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 in 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 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 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 have 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 cost. 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 cost numbers. It's a product of the fact that our Spraberry/Wolfcamp horizontal wells show a very low-cost production. 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, a 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 this 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 3 cargoes interestingly have gone to 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'll 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 getting 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 2 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 in the longer-term growth forecast 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 2 rigs and the other part related to the fact that we're using third-party frac fleets in the Eagle Ford Shale and that 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 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 4-string casing design where it's necessary. It's probably today 3/4 of our wells. That number will be reduced going forward.

We did put our -- put the number of wells planned on production, our POPs, over 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 EURs, 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 will be about 70. That will get us to the 230 target that we have 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 campaigns, 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 6. 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 to be wider spaced than their earlier campaigns and have higher intensity completions, along the lines more of what we used in the Permian Basin to see if we can 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 9 were the DUCs in the last couple of quarters. They're basically 2x their 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 of wells to be drilled.

A couple more wells have POP'd, been POP'd here in early October, so we're just starting to see those results, and the last 7 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 the 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 7. Our capital remains essentially the same except for what I mentioned earlier, which is the accounting for the addition of the 2 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 flows coming in roughly at $1.9 billion. I think that's likely conservative because based on $49, $50 going forward for the fourth quarter on oil today, with prices 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 8. 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 finished 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 9 more years, and that will include 700,000 barrels a day of oil at that time, and we'll have more on that in a couple of slides.

On Slide 9 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 9 from sell-side research, you can 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 -- in the next 9 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 2 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 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. And 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 it between $57 and $58 in that range, we 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 higher 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, on production per share, on operating cost, 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 9 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.

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 budget and lateral length, 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 $50 and $3.

Moving to Slide 13. Here, we are showing results from 12 of our Version 3.0+ wells for 3 -- or for 4 of our 3-well pads. All of these wells were POP'd in Q2, which is significant because now we have 4 to 6 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 length. 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 Hutt and South University Wolfcamp Bs were completed with 30-foot cluster spacing and 150-foot stage length. And the Pembrook wells were completed with a 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 3 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. 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 2 new wells in Q3 in the northern part of our acreage. The significance of these 2 wells is that they represent our first spacing test, so we're going to be looking forward to the results of those 2 wells. The other 9 wells continue 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, as 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.

Thank you, Joey, and good morning, everyone. Turning to Slide 16, Pioneer is wrapping up our 2017 drilling and completion program in the Eagle Ford. The plan is to complete and POP 20 wells during the year, including 9 DUCs drilled about a year ago and on to 11 new wells, testing design changes expected to significantly increase recovery. The design changes include longer laterals, increased well spacing, 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 2x 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 2 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 2 wells POP'd early in October. We are very pleased with our 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 the financial results.

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 noncash 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 guidance on 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 if you include those hedging results.

Turning to Slide 20, looking at production cost per BOE. You'll see that production costs in total were down 3% quarter-over-quarter. Excluding taxes, production costs were down also 3% versus QT -- 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 2 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 cost. 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.

And 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 a 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 to 302,000 BOEs per day. The rest of the items on this page are consistent with prior quarters, other than 2. I'll note that production cost. 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, Gina. And we'll open up the call for questions.

(Operator Instructions) And we'll take our first question from Dave Kistler of 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 will get you 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?

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 to 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 will 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 what we expect to see inflation in some areas. And as a result, I think we will stay pat with our plan for 2018.

Okay, appreciate that. And then 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 '18.

Yes, I think the current work we're doing, and of course, 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 dealings with the board and other matters. But current thought would be POP-ing 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.

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.

I think that's right, Dave. If you look at it -- 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 '18 and into '19. But for the time being, the way they should be thought of is increasing our utilization rates, 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 combination of the 2, the early stage being operational flexibility, having the #1 priority. And secondly, it will then contribute to production growth in the second half of the year and into 2019.

And our next question comes from Arun Jayaram of JPMorgan.

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.

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 determined that the 2015 and '16 campaign had delivered. We really got too far downspaced, we feel 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 1/3 natural gas and 1/3 NGLs in addition to 1/3 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 9 years, we'll be drilling quite a large number of Jo Mill locations as it relates to that plan. And because these results look so strong, I'm very encouraged by that.

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 could comment on how the cost looked like relative to 3.0 and how you're thinking about moving the program shifting towards perhaps more Version 3.0+ completions in '18 and beyond.

Sure. Well, first of all, if you look at the cost associated with the 3.0+ as compared to Version 3, you -- and 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, we look at the 3.0+ results. They look really outstanding and clearly well in excess of 5% or 10% 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.

Our next question comes from Doug Leggate of Bank of America.

Tim, can I -- maybe if Joey wants to take this one, but if I can go back to Slide 13, I just wonder if you could 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? Is that -- are you seeing significant differences versus the prior design? Just walk us through what the thought process was there, please.

Sure. To clarify, we've only done one pad of 3 wells. Each one had 156 sliding sleeves. The most important thing to back up on as why we did the test. This was in Lower Spraberry Shale, and we did it for 2 objectives. Number one, whenever you're in the shallower, lower-pressured zones, it creates some -- a little bit less efficient on the drill outside 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 that right now is it's relatively new technology, so the operational piece of it is 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 5 or 6 clusters at a time. So this whole debate that people sometimes get into on how effectively are you stimulating 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 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.

I realized 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?

So it's very early. We just turned these wells on in the last month or 1.5 months, so it's too early to tell. I will tell you that I think preliminary indications are -- 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.

Okay, I appreciate that. I just have 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+?

Everything we're doing right now, Doug, is defaulted to 3.0.

Okay. And last one from me is really, just going back to the other 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/Wolfberry program -- or Wolfcamp program, rather. What is the longer-term prognosis for the ex-Permian assets? And I'll leave it there.

Thanks, Doug. Yes, I think what we're going to be doing is evaluating all of these wells and their impacts on the inventory. 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 that gives us 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'll evaluate as we see the fullness of the program completed here with these 7 wells, putting those on production in November and watching their production. We'll make some assessment as to that question as we get into early part of next year.

Do you plan any capital in the Eagle Ford in 2018?

That's a 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.

Our next question comes from John Freeman of Raymond James.

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 million 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 are using.

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. As a matter of fact, we have some that were 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 assumed the 1.3 million EUR.

Okay. And then just my follow-up, sticking with the Eagle Ford. Obviously, on the well cost, you all mentioned it's 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 fleet just given where the costs are or if that's still kind of off the table?

Certainly, I think we consider that. I mean, realizing today, we operate, among our whole set of fleets depending upon the day, 6 or 7 fleets. Now that said, we have 8 to -- fleet number 8 and 9, 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.

Our next question comes from Evan Calio of Morgan Stanley.

You mentioned 250 to 275 POPs, wells POP-ed in '18. 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?

I think if you look at the POP count, this is more of an estimate of the overall number. We have not gotten yet to 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 gave 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.

And the midstream?

Yes. If you look at the additional cost 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 as an alternative to our sand supply. So we don't have to expand the Brady plant today. We're evaluating its competitiveness from a go-forward standpoint and the expansion versus these other alternatives. That said, we are going to need to be spending money on third-party processing. Targa has 2 new plants planned for 2018, one coming in place in March and the other one roughly around September. Those will demand capital as well. We have regular infrastructure needs, of course, going forward and compression in the field with Targa. But 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 '17. So roughly flat at about $150 million or so compared to 2017. That's going to be the material number when it comes to our overall other expenditures.

Great. My 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. 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, relatively more mature portfolio stack. When you look at the life of the asset post 1 million barrel of growth, I mean, do you see a multi-decade plateau where cash distributions become a defining characteristic of the asset? Maybe just your thoughts there on returns versus growth and maximizing shareholder value longer term is appreciated.

As I mentioned earlier, we're very heavily focused on getting to free cash flow generation. Actually, our first goal is to hit 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 9, 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 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 9 years, as I said, without issue just simply 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 other 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 into a very strong position from the standpoint of oil exports and their importance in terms of the global energy picture.

Right. A very different long-term outlook.

Our next question comes from Scott Hanold of RBC Capital Markets.

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 going to pay for it and put it to work right away?

I think that's a great question. 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 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 had 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 to be really careful in consideration of that. The second point is we haven't even drilled some of the locations or some of the zones yet, realizing coming up we're going to be drilling our first Clearfork well horizontally in Midland County. And we've also said, we have not even drilled a Wolfcamp C well ourselves. Fortunately, Parsley has done 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 in some of the deeper locations, the 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'd see them productive in the Delaware Basin. Haven't drilled a well there. It's deeper drilling, so it -- and it would probably be more gassy. So in the (inaudible) 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 interest or zones when we don't even know what it as 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 will otherwise being unlocked as to their potential to technology change, we will be remiss if we can 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 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.

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 you would like to harvest some of the cash -- harvest cash from that asset?

Yes, I think a zone sale is a possibility, I mean, in essence, we've already done that in the South, where our partner, 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 who's going to come in and drill on our same footprint, that causes other issues, right? And they are always bumping into each other. It's also a situation you bring someone in, drill the same zones underneath areas where you're drilling other zones, you have competition for the same services. It theoretically has 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.

Okay. Okay, that's great. And then as a follow-up, I think you mentioned that right now, you're doing about 75% 4-string. And could you just give us an update on some of those, the recent progress there? How fast those wells are getting down if you're seeing some improvement as you do a little bit more in? What could that percentage looks like in 2018?

Yes, okay. I will let from Joey answer that question, Scott.

Yes, Scott, the 4-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 2 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 3-string in areas where we're doing 4-string. So our hope is to continue to progress the 4-string but also look for opportunity to go back to the 3-string wherever we can.

And our next question comes from Charles Meade of Johnson Rice.

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 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 Pembrook, on the Pembrook pad, those results actually don't look like they have as much uplift as kind of the lower end of that 3.0+ intensity with the 50 barrels and the 3,000 pounds per foot. So I wonder if we could -- you can kind of share what your preliminary thoughts in there, and perhaps it dovetails a little to what Joe 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.

Yes, Charles, so one of the things to keep in mind if you look at that Pembrook test is that that's a 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 particular, in the Pembrook 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, 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 2 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 mind-set on this going forward.

That's helpful insight, Joey. And I really appreciate those, I guess, unseen variables there. And then Tim, perhaps a question back for you. When we talk about or when we kind of look at the impact of accelerating these 2 rig adds, can you give us an idea of kind of on a Spraberry/Wolfcamp program-wide basis, how many drilled, uncompleted wells in inventory were you looking at, say, in 2Q of this year? You -- so kind of your work in process inventory. And what kind of level do you think 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?

That's a great question, Charles, and that's right on point with what we're trying to achieve. First of all, if 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 other rigs, we then get up to, let's say, a range of let's just say 35, 40 DUCs. That's the sweet spot because we're going to have 7 or 8 completion units out there, frac fleets, 3-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 2 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.

Our next question comes from Michael Hall of Heikkinen Energy Advisors.

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 time frame forward? And if so, how far forward do you think it could?

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 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, end of 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 date significantly. So that's exactly what the results should be to the extent we went in that direction.

Okay. And have you attempted to maybe estimate what sort of time frame impact that could have at this point yet? Or is that premature?

That's too early. Just 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 where we can actually give you those level of details.

Fair enough. I 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, updated that number. I guess, how would you think about the declines on that business as well as the Raton and Panhandle in 2018? How should we kind of handicap those declines at this point?

Well, I think you already have the Eagle Ford number in there. I think you can actually look back in our materials and we have the information in production from all the areas as to each quarter over the last couple of years or so. And I'm referring specifically to Slide 24. If you look there, you can see Raton basically has been pretty flat. I mean, it's 100% methane, but you can see each in the last 3 quarters, it's produced within 1 million cubic feet a day of the prior quarter. So it's a 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 generally, if you look back through time, it has exhibited roughly about a 10% decline rate.

Okay. And in the Eagle Ford, though, that 35% is pretty fair going forward as well? That doesn't slow down at all?

It's obviously a product of how much you drill, but that's correct. I mean, that's the basic fundamental decline rate.

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, do you think, as you look over the next few years towards that breakeven time frame in 2020? With the current plan at a sort of $50 world, have you -- do you have a view on how that looks over time?

I'll let Rich answer that one, Michael.

Yes, I think when you look at the modeling on it and the returns these wells are generating over the next 4 or 5 years, that will go into double-digit range. So you look at it adding a couple of percent per year based on the 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 a pretty significant improvement, given the high rate of returns these wells are generating over the next 4 or 5 years.

And that's basically a 50, 55 case.

That's right.

And our next question comes from Brian Singer of Goldman Sachs.

I want to follow up on a couple of 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 toward those incentives are changing? Or if it's simply a publication in a proxy of what's already in existence today?

That's a great question. Internally, of course, we look at every variable, and some of them are intertwined, right? I mean, it depends on how -- your finding cost ends up touching your DD&A rate and so on. But the fact is -- and actually, and your capital spending, FX, your debt numbers as well. So a lot of these goals are intertwined. But as you look at our incentives, we look at all of 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 have that resolved 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.

Great. And my follow-up is back to the casing and the 75% of wells currently using the 4-string and that number falling. You highlighted the Lower Spraberry and Jo Mill as 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.

No. Yes, Brian, we don't see any change in the southern acreage. We see that still going forward as 100% 3-string.

And also, are you changing your shift of POP mix or the number of wells that you're drilling in the southern area?

We still are planning to run 4 rigs in the southern acreage.

And that concludes today's question-and-answer session. At this time, I will turn the conference back to the speakers for any additional or closing remarks.

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.

This includes today's call. Thank you for your participation. You may now disconnect.