May 5, 2017
Executives
Frank Hopkins – Senior Vice President-Investor Relations Tim Dove – President and Chief Executive Officer Chris Cheatwood – Executive Vice President and Chief Technology Officer Joey Hall – Executive Vice President-Permian Operations Ken Sheffield – Executive Vice President-South Texas operations Rich Dealy – Executive Vice President and Chief Financial Officer
Analysts
Arun Jayaram – JPMorgan Brian Singer – Goldman Sachs Doug Leggate – Bank of America Merrill Lynch Charles Meade – Johnson Rice Evan Calio – Morgan Stanley Michael Hall – Heikkinen Energy Advisors John Freeman – Raymond James Neal Dingmann – SunTrust Jeffrey Campbell – Tuohy Brothers Phillip Jungwirth – BMO Capital Markets Scott Hanold – RBC Capital Markets
Operator
Welcome to Pioneer Natural Resources First Quarter Conference Call. Joining us today will be Tim Dove, President and Chief Executive Officer; Chris Cheatwood, Executive Vice President and Chief Technology Officer; Joey Hall, Executive Vice President, Permian Operations; Ken Sheffield, Executive Vice President, South Texas operations; 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 these slides related to today’s call is at www.pxd.com. At the website, select Investors and select Earning and Webcasts.
This call is being recorded. A replay of the call will be archived on the Internet site through May 29, 2017.
The company’s comments today will include forward-looking statements made pursuant to the safe harbor provision of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties are described in Pioneer’s news release, on Page 2 of the slide presentation and in Pioneer’s public filings made with the Securities and Exchange Commission. At this time, for opening remarks, I would like to turn the call over to Pioneer’s Senior Vice President of Investor Relations, Frank Hopkins.
Please go ahead, sir.
Frank Hopkins
Thanks, Kyle. Good day, everyone, and again, as every quarter, thanks for joining us.
I want to briefly review the agenda for today’s call. Tim is going to be the first speaker.
He’ll provide the financial and operating highlights for the first quarter of 2017 and give you an update on our plans for the rest of 2017. As Tim commented in our earnings press release, Pioneer delivered another great quarter.
We had solid earnings, strong production, continuing impressive horizontal well performance and reduced production cost. After Tim concludes his remarks, Chris will briefly discuss how Pioneer is taking advantage of leading-edge technologies and how innovation is expected to improve productivity as we progress towards our 10-year vision.
Joey will be up next, and he’ll review our strong horizontal well performance in the Spraberry/Wolfcamp. He’ll also provide an update on drilling plans for the remainder of the year in his area and a progress report on the buildout of Pioneer’s water distribution system.
Ken will provide an update on the limited drilling program we have underway and the Eagle Ford Shale this year. And last, Rich will summarize the first quarter financials and provide earnings guidance for the second quarter.
And after all that, we’ll open up the call for your questions. And with that, Tim, I’ll turn the call over to you.
Tim Dove
Thanks, Frank. And once again, welcome to our first quarter conference call.
The first quarter, as Frank mentioned, was a strong start to the year, and the company is doing exceptionally well, both in terms of production this quarter as well as the fact that prices were up while we’ve been able to stabilize cost and, actually, have lowered cost in some areas. I will talk about that in a few slides.
As Frank also mentioned, we’re excited to have a couple of interesting new topics for you. One is the granularity surrounding our technology and innovation initiatives as well as our water sourcing strategy.
In the quarter, we reported adjusted income of $42 million, or $0.25 per diluted share. Production came in above the top end of our range at about 249,000 BOE per day.
That was a 7% increase or about 3% from last quarter. And importantly, we continue to show the ability to grow even since the downturn commenced and we expect that to continue.
The growth for the quarter, of course, was driven by the results from our continuing Spraberry/Wolfcamp horizontal drilling campaign, and Permian production increased 7% quarter-over-quarter. Importantly, our new wells continue to perform really well.
Permian oil production met our expectations for the quarter even though we only popped 38 wells instead of the 45-or-so that we had planned on, which indicates that well performance continues to exceed our expectations on the oil side, especially based on the Version 3.0 completions. We’ll talk more about that in a few slides.
The shortfall in POPs is really only a timing issue and we’ll see that sorted out as some of it slipped into April. Also, on the gas and NGL front, our gas and NGL production exceeded our expectations in a very material way.
And to a great extent, we have Targa, our operator of our gas plant systems, to thank for that. They did a great job in terms of increasing NGL yields in response to higher pricing during the quarter, especially during January and February.
In addition, by bringing on a plant that had been mothballed and also looping some pipelines and adding several new field compressors, we saw a reduction in line pressure in various areas of the field by about 2 psi. And that may not seem like a lot, but that represents about a 5% reduction in pressure in the system in certain areas of the field, which allows more gas to flow into the system.
So even though this increased percentage of gas and NGLs produced was a significant number, it’s a good thing because it represented about $4 million of additional cash flow that was generated in the quarter than we had expected. Our costs, as I mentioned earlier, were in line, and in a couple of cases lower, particularly on operating cost.
Our electricity costs were down 4% or 5%. But really, more importantly is we saw a reduction to $6.31 per BOE from $6.42 at the prior quarter.
We continue to benefit from the fact that our Spraberry/Wolfcamp wells are very attractively produced at about $2.33 per BOE. That excludes production taxes.
So the more of those we drill and contribute to the mix, we can keep our production cost going down. And we continue to have one of the strongest balance sheets in the entire industry sector, and we did repay a debt maturity in March from cash on hand, that’s reflected in our current cash balances.
We were upgraded by all 3 rating agencies this quarter and we’re extremely pleased about that. Debt levels, of course, remain exceptionally low.
Turning now to Page 5, and as previously announced, we were able to close a couple of sales regarding some Permian acreage, in particular, Upton, Andrews and Martin County for a grand total, considering one that closed in April of about $330 million. And we have, as we had telegraphed earlier, moved to 18 rigs in the first quarter in the Spraberry/Wolfcamp trend area.
I mentioned a minute ago, but we did place a relatively low number of POPs on the schedule this first quarter. Only 38 wells were put on production.
That had to do mostly with the rig timing from when those rigs were put on late 2016 and into early this year. That should be expected to obviously change, going forward, where we would expect 60 or 65 POPs in the second quarter and even larger numbers in the third and fourth.
In other words, our production, as a result of our POPs schedules, is back weighted for the year, and in fact, it will be back weighted for the second quarter as well. What is important to say is Version 3.0 is now our default completion.
Joey will talk about the impacts of Version 3.0 optimization, but you’ll see that the 3.0 wells continue to well exceed Version 2.0 wells. And we’ve got a couple of slides in here regarding new zones, but in particular, the Jo Mill section, we’re now going to show you several wells that have been drilled over the last couple of years to show how we think the Jo Mill can contribute in significant way.
It is emblematic with our efforts to build more data on these new zones. We’re becoming a big exporter, I would say.
We exported 1 million of Permian oil to Asia and Latin America during the first quarter. We have another 1 million barrels scheduled to ship out to Europe, actually to Northwest Europe and the Mediterranean during the second quarter.
So as we look forward, as we continue to grow oil production, the export market is going to become a bigger and bigger part of our marketing focus moving forward. Now turning to Slide 5, the 2017 update.
Of those 18 rigs that was working and working in the North with a balance in the South, we will be testing some new completions, although as I said, 3.0 is our default. But there’s about 15 wells that we’ll be testing.
For example, sand volumes from 2,500 pounds per foot up to 3,000 pounds per foot. And even in one particular case, a 3-well pad on shorter laterals with 5,000 pounds per foot.
So we’re not ready to rename something in excess of 3.0 as a new version yet. That certainly would be interesting to see those wells as they come on production as we get into the second and third quarters.
We are maintaining our forecast for our growth at the Spraberry, Wolfcamp. It’s expected to grow 30% to 34% compared to last year, and oil production still maintained at 33% to 37% growth.
Ken Sheffield is going to come on in a minute and talk about what’s happening in the Eagle Ford, but suffice it to say, we are now operating with 2 rigs. We have one outside completions fleet that’s now working on our drilled but uncompleted wells in the Eagle Ford.
And the total wells to be drilled this year remains at 11 new drills and 9 completions of formerly uncompleted wells. And what we’re really trying to do here is use Permian-style completions, higher-intensity completions, to see if we can improve the well results at a wider spacing.
We were successful during the quarter of moving our gas processing operations away from what had been a difficult plan to operate after all these years at our Fain processing facility through a third party and are now of taking most of the gas from that facility. And what it should help us, of course, is to reduce our NPT, our nonproductive time issues, that we’ve been dealing with now for several months.
We believe that we’re still on this range. We remain in the range of about 15% to 18% production growth, oil being up 24% to 28% this year.
And what’s really important, of course, is that our returns are holding up and we’re still looking at 50% to 100% returns with allocated facility cost included for our D&C program for this year. Now turn to Slide 6 and just continuing the update.
Of course, there are a lot of moving parts when you’re using corporate percentages, but the main message from our standpoint is that our oil forecast remains intact and on the numbers that were expected. We’re going to reduce the forecasted oil content from 62% to 60% though service related to the third bullet point, which is to say we expect the same things we saw in the first quarter, which is the benefits of Targa’s work to reduce line pressures and so on, to increase our gas production and NGL recoveries in the Permian Basin.
Again, that’s a good thing. We’ve got a couple of other adjustments that’s going to change the overall corporate percentages.
One is the fact that we did sell the Martin County acreage I mentioned earlier, which was very highly oily area. So we lost about 1,500 barrels a day of 80% oil.
And then, related to the transferring of the gas processing operations, there was 1,000 barrels a day or so of light condensate, we call it drip condensate in the field -- actually, in the plant operations that had been sold as part of the condensate stream separately that will now be going down the pipeline and processed as NGLs as we have to reclassify what had been considered oil in the mix now to NGL. And that, of course, changes the corporate percentages as well.
The fundamental is, though, there’s really nothing changing the underlying our oil production, our oil forecasting, we’re just fortunate we’re able to actually get increased revenues at the gas and NGLs as we move forward. We’re going to remain with a capital budget of $2.8 billion.
That’s the same number we’ve had all year. That’s $2.5 billion for D&C and $275 million for vertical integration investments.
We still see some cost inflation. In some areas, it’s up to 10% to 15%.
We see other areas that are single digits. We’re assuming about a 5% net cost inflation to our operations, but I think I’m pretty confident at this point to say that what we’re doing in terms of both vertical integration and improvements in productivity will offset that 5%.
So I don’t expect to be impacted by any significant amount of inflation in 2017 at the bottom line. That will be easily funded by the current estimates based on prices of about $2.3 billion of cash flow and the additional cash on hand.
We did, of course, finish our 2017 hedging program just this last quarter, where we now have both oil and gas hedged at about 85% of production. We did begin to build a 2018 oil book.
We’re actually a little over 20% of forecasted oil production now and 15% of gas production for next year. And we’ll potentially look to add more hedges around or perhaps after the May 25th OPEC meeting.
Our efforts to sell approximately 10,000 acres in the Eagle Ford Shale continue. Those negotiations are ongoing, and we’ll have more to say about that when those negotiations come to fruition.
But ultimately, our measures continues the same. We’re going to be drilling a high-return program, and it’s that which allows us to say 2018 still appears to be the year when we spend within cash flow, and then 2019 and thereon are years that we will have cash flow exceeding our capital needs in order to grow 15% plus, going forward.
Turning to Slide 7. This slide has not changed.
As you might guess. It’s been from our earlier comments.
Our first quarter spending in terms of cost to drill was $524 million. That would appear to be, of course, low, but it’s indicative of the fact that we didn’t have as many POPs in the first quarter, and it is, therefore, also indicative of a back-end-loaded POP schedule for the year, and we’ll catch up – we still believe we’ll be right on that budget for the entire year, funded, as I mentioned earlier, from cash flow and cash on hand.
And then turning to Slide 8, my last slide. We still are in beautiful position.
I feel like to perform well vis-à-vis our vision to grow 15% plus for many years and reached that one million BOE per day target in 10 years or so. This year, of course, we’re maintaining 15% to 18% growth, and that incorporates 24% to 28% oil growth.
Again, the second quarter numbers are shown here. You might expect them to be higher in a scenario where you just calculate up the impact of certain number of POPs in the second quarter compared to the first.
But the fact is just the way the rig schedule works, the vast majority of those POPs are in May and June, so we don’t get as much of an effect as you might expect from the actual number of POPs. We’ll see a bigger effect in the third quarter.
So I’m going to stop there, and I’m going to pass it over to Chris Cheatwood. Many of you know Chris as our EVP of Geosciences and Business Development.
But most recently, he’s been named Pioneer’s Chief Technology Officer, and he’s going to give you just a quick summary of some of the things we’re doing in our technology and innovation initiatives.
Chris Cheatwood
Thanks, Tim. Let’s go to Slide 9.
Most of you guys know that our company has used leading-edge technology for many years. A number of them are listed on this slide, but for the sake of time, I’m only going to discuss a couple of them.
Also, my focus is going to be on the Permian, but the same is true for South Texas. We geosteered over 1,600 wells in multiple areas over the last 10 years.
In the Permian, we’ve used 5,500 square miles of 3-D seismic in the Midland Basin combined with extensive core. Our proprietary petrophysical model is based on over 1,600 wells, and those have allowed us to build rock property volumes covering our multiple reservoirs.
The graphic at the top right is a great display of the information we used to target when we steer our wealth. With operations covering over 5,000 square miles in the Midland Basin, we must monitor and operate from centralized control rooms.
We have replaced our legacy SCADA systems, with a single web-based platform to allow us to automate the edge via IoT technology. Mobility is also integral to this new system.
Our most advanced example is our fully automated water distribution system that will be discussed later. Now let’s turn to Slide 10 and get a glimpse of the future.
The bullets on the left highlight some of our technology initiatives to change the way we work on our journey to million in 10. As on the previous slide, I’m only going to elaborate on several examples.
We are using the supercomputers and the GEOS software at Lawrence Livermore National Laboratory to model and visualize in 4-D the propagation of fractures when we stimulate the shale reservoir. the shale reservoir.
Combining our real-world data with Livermore’s computing power and cutting-edge code will lead us to a state-of-the-art solution for reservoir development. Pioneer Pumping Services fluid ends were only lasting around 300 hours before failing due to metal fatigue.
Working with Oak Ridge National Labs, we’ve produced a proprietary fluid end with improved metallurgy in forging to increase the service life tenfold. The first one is in the field and it has passed 750 hours so far.
i. Expects to scale production in the very future.
We are building a new physics-based drilling system comprised of three components being developed jointly with third parties. First, the dynamic drill string modeling software; second, a proprietary downhole tool to gather and transmit high-frequency data; and three, a real-time prescriptive analytics platform.
This will be the ultimate continuous improvement drilling system when completed. I’ll now turn it over to Joey Hall to talk about Permian operations.
Joey Hall
Thanks, Chris. I’ll now be picking it up on Slide 11, where Version 3.0 completions continue to show impressive profile over 2.0 with 16 new POPs in Wolfcamp B and 12 new POPs in Wolfcamp A.
This is our first time to show the improved performance of 3.0 wells in the Lower Spraberry Shale, where we have 17 version 3.0 wells, 10 of which came on in the first quarter. We expect our Version 3.0 wells to pay out the incremental cost of $500,000 to $1 million in less than one year.
Looking forward, we have several larger completions planned for the rest of the year, as Tim had mentioned, testing sand concentrations between 2,500 and 5,000 pounds per foot and water concentrations up to 100 barrels per foot. We also plan to continue testing variations of cluster spacing and stage lengths.
Now going to Slide 12. Here, we are showing the encouraging performance of five Jo Mill wells that have POPs since Q4 of 2014.
As you can see from the map, these wells are spread throughout our acreage and they are also a mixture of 1.0 and 2.0 completions. Average EURs are 900,000 BOEs for 6,800-foot laterals, and going forward, we have six Jo Mill wells planned for 2017, where we will be testing longer laterals, spacing and variations in the completions.
Now moving to Slide 13. Really no changes here from our last report, still estimating 260 gross POPs for the year, same estimates for well cost, EURs and production costs and still forecasting robust IRRs of 50% to 100% for Version 3.0 completions of $55 oil and $3 gas.
Now moving on to Slide 14. Pioneer continues to work on meeting our long-term water needs.
Our water demand has more than doubled from approximately 150,000 barrels per day in 2014 to 350,000 barrels per day expected in 2017. And with our current completion design, our needs could quadruple by 2026.
We remain focused on lowering cost and reducing the use of freshwater by increasing our use of brackish, effluent and produced water. As Chris mentioned, we’re also leveraging automation to ensure we are delivering water to our locations in the most efficient manner we possibly can.
Continuing the water story on Slide 15. Today, we spent approximately $300,000 – or $300 million through 2016 for partial completion of the 100-mile mainline, the Odessa effluent water tie-in and a network of subsystems, ponds and water wells in our major drilling areas.
We expect to spend $160 million in 2017, primarily for continuing construction of the mainline and additional subsystems and ponds. We’ll also start the engineering for upgrades to the Midland wastewater treatment plant, where we will spend approximately $115 million from 2017 through 2020 to secure the supply of approximately 240,000 barrels per day of low-cost effluent water.
We ultimately expect our investment in water infrastructure to reduce our cost by $500,000 per well. Wrapping up my Permian update on Slide 16.
We finished the strong quarter with 38 POPs and averaging 201,000 barrels of oil equivalent per day, which is 13,000 BOEs per day or 7% over our Q4 2016. Our oil production was in line with expectations, while gas and NGL production was higher than expected due to lower line pressures across the field and improved NGL yields.
Our expected 2017 production growth of 30% to 34% remains unchanged. We plan to POP 60 to 65 wells in Q2, primarily weighted toward the second half of the second quarter.
This will leave 70 to 80 POPs in each of the remaining 2 quarters to close out 2017. As I discussed last quarter, the variation of POP counts is caused by the cyclical nature of an 18-rig program and a few POPs from – sliding from March into April.
Also keep in mind that we added 5 rigs in Q4 and 1 in Q1, and there’s a 5-month cycle time before you start seeing the POPs. With that, I’m going to turn it over to Ken Sheffield to talk about South Texas.
Ken Sheffield
Thank you, Joey, and good morning, everyone. Turning to Slide 17.
Pioneer’s limited D&C program is underway in our Eagle Ford asset. We’re currently operating 2 rigs to drill 11 new wells this year and we’ve commenced completion operations for the 9 planned DUCs.
We plan to complete and POP 20 wells during the year. 11 new wells will test design changes expected to significantly increase recovery.
The design changes include wider spacing, 44% longer laterals, tighter cluster spacing and much higher POP concentrations, which have yielded strong results in both Eagle Ford and Permian operations. The cumulative effect of the design changes are expected to yield EURs, averaging 1.3 million barrels equivalent.
Well results will be evaluated in the second half of 2017. I’ll now turn it over to Rich Dealy to review the financial results.
Rich Dealy
Thanks, Ken, and good morning. I’m going to start on Slide 18, where we reported a net loss attributable to common stockholders of $42 million or $0.25 per diluted share.
That did include noncash mark-to-market derivative gains of $90 million after tax or $0.53 per share. That’s really a result of lower oil prices at the end of March on a futures basis, relative to what they were end of December.
Also during the quarter, we had 2 unusual items that netted to a charge of $174 million, or $1.03 per share, mainly – main component of that was an impairment charge that was noncash related to Raton, really due to the decline of long-term gas prices is really what triggered debt impairment. So adjusting for those items, we’re at $42 million of earnings or $0.25 per diluted share.
Looking at the bottom of the slide, where you can see how we did relative to guidance, you can see that as Tim mentioned, we’re above our production guidance of 249,000 BOEs a day for the quarter. All the other items are either on the positive side or within guidance, other than exploration abandonment and we’re slightly above guidance there mainly due to 1 well that we had some mechanical problems on during the quarter that we had to plug.
Turning to Slide 19. Looking at price realizations.
Really, overall, an exceptional quarter on price realizations, with improvement across the board. You see that oil prices were up 6%, the lower $49 per barrel.
NGLs were up the most, up 15% to $19.33. That’s primarily due to higher realizations on propane and butane prices during the quarter.
And then gas prices were up 8% for the quarter. And unfortunately, as we move into April, as Tim mentioned earlier, prices have come down some and pulled back some.
And so currently, based on where the projections are, second quarter realizations will be slightly lower than the first quarter. Obviously, a lot depends on what happens on the May 25th OPEC meeting and how that will influence oil prices.
Turning to Slide 20 on production cost. For the quarter, production cost in total were up 3%.
But as Tim mentioned, the majority of the increase or all the increase, really, was due to production taxes and ad valorem taxes being about 19% quarter-on-quarter. Otherwise, production cost, without taking in account taxes, would have been down 2%.
Base LOE for the quarter was flat quarter-on-quarter. Workovers were a little bit higher during the quarter due to the improvement in commodity prices and a little more activity than in the Permian Basin.
Turning to Slide 21. Liquidity position.
We continue to have excellent position, with net debt under $400 million. As we mentioned earlier.
We did pay off the bond that matured in March, with cash on hand. And we’ve been upgraded, highlight of the quarter, by all 3 agencies, really reflecting the company’s strong financial position and strong outlook for financial cash flow-positive situation.
Turning to Slide 22, looking at second quarter guidance. Daily production of 254,000 to 259,000 BOEs a day for the quarter, so up from first quarter, substantially.
And then really, the rest of the items are either consistent with prior quarters or down slightly as we continue to work on our cost structure. And so those are there for your review, I’m not going to cover those in detail.
And so why don’t I stop there and move on ahead and open up the call for questions?
Operator
Thank you. [Operator Instructions] We’ll take our first question from Arun Jayaram with JPMorgan.
Arun Jayaram
Good morning. Tim, I wanted to talk to you a little bit about your plans on a go-forward basis, perhaps to shift, and thoughts around kind of a multi-zone kind of development kind of strategy.
Because if we think about the Permian today, a lot of operators are doing kind of 2- to 3-well pads. But if you get into full development mode, how could you – how do you think you’d adapt that thinking about kind of a multi-zone kind of strategy?
Tim Dove
Yes, Arun, that’s a great question. I think if you look at these zones that we’re talking about completing, there are many now, and in particular, as Joey commented on, the Jo Mill is now coming to fruition with more data.
And so when we move ahead, you’re right, we will probably take a look at opportunities to grow more than 2 or 3 well pads. But in principle, one of the main changes we’re making is with 24 well bay models, we’ll actually be drilling 24 wells from a set of well base.
Not dissimilar from what we used to do in Alaska. Of course, in Alaska the reason we have well base is because we didn’t have that much space and it had to be indoors.
But in this case, it’s allowing us to have a significantly lower footprint and we’ll be able to drill multiple zones from that 24 well bay scenario, and we have those in place today in the field. And it wouldn’t be unusual within those 24 well base to drill Wolfcamp Bs, come back and drill Wolfcamp As.
You’ve got others drilling Lower Spraberry Shale wells, Jo Mill wells and so on. So I think what you’re going to see is that model is where we’re going to go forward, that is to say with our 24 well bay system.
Arun Jayaram
Got you, that’s helpful. And just a follow-up.
You kind of addressed this, but I just want to make sure I understand. There’s a decent kind of kerfuffle on your oil mix going down a little bit.
You highlighted some of the reasons why. As you think about your EURs and the recoveries, is there anything changing relative to EURs and how oil – in terms of the oil volumes?
Or is there just better recoveries through some of the things that Targa is doing, et cetera?
Tim Dove
Yes, I think, of course, when you’re dealing with percentages, corporately, there’s a lot of moving targets and a lot of moving data points. But as it relates to our wells, our wells are coming in, as Joey showed, we can show it in any sort of mix of 3.0 style wells better and better as we apply the new technologies, and actually, just use more in the way of the same sort of completions that we’ve done.
And I think that will be the case as we look forward in terms of – when we go past 3.0 to 3.5 or 4.0. And we’re testing those 15 wells, as I mentioned, this year.
I think when you look at it, though, from an internal data’s perspective, these wells come in just like all the prior wells. And so there’s no change in the mix in terms of how well is produced, how they come online.
And as you know, it depends on where you are. It’s not unusual to have the wells coming in at 70%, 75% oil in certain zones and up to 80% or slightly over 80% in other zones.
And so we’ve seen no change, whatsoever, in the sort of oil mix in the wells themselves. What does happened through time, as you know, is that the gas-oil ratios go up through time in these wells, and that’s been the case in vertical wells.
We’ve drilled 7,000 vertical wells, so we know what we’re talking about here. You can see a gradual increase in GORs, in wells through time.
But as it relates to the initial production of these wells, they’re right, spot on.
Arun Jayaram
Okay. Thanks a lot, Tim.
Operator
We’ll take our next question from Brian Singer with Goldman Sachs.
Brian Singer
Thank you. Good morning.
Tim Dove
Hi, Brian.
Brian Singer
You talked about cost mitigation in part because of the vertical integration that you have. Some of the oil services companies have highlighted that their own cost structures are rising here up bottom.
Are you seeing that at all in the areas where you are vertically integrated? And then separately, when we look at the $2.33 per BOE production cost coming from Permian horizontal wells, how should we think about that trajectory over the next year?
Tim Dove
Yes. First of all, on the vertical integration, what you have to sort of figure out in our case is most of our supply that’s needed to complete wells is also vertically integrated, which is to say, we provide, to a great extent, all of our Brady Brown sand, even from our mine or from other mines in Brady.
And so we have long-term contracts in place for the third-party sand, which were very favorable – at very favorable prices. And of course, we produce our own sand at cost.
Our water system is very material to this question and we’re delivering water cheaper right now than anybody can do it, and we’re just in the process of building that system out. So when you look at other costs such as GOR and other chemicals, they have not really moved materially.
So the actual cost structure – and maybe you can also say labor has moved up, say, 2% to 3%. But if you look at the base cost of completing these wells, they’re not substantially higher for us than where they were several months or quarters ago.
It’s just that with the tightness in the pumping services, that’s going straight to margin to a great extent, but it certainly won’t affect us. We will just be actually in a position where our pumping services will be making money this year if we just mark-to-market that business in terms of its activities with market price revenue.
So I think the fact is it’s going to have a very positive effect, offsetting cost of wells. Secondly, on your horizontal production cost, I think the $2.33 number is a good number, going forward, for the horizontal Wolfcamp development and Spraberry horizontal well development.
I think if you look at it, still the majority of those costs are personnel, electricity, chemicals and so on. And it’s just simply the fact that these are so high-producing wells, especially earlier in their life, that to the extent we continue to accelerate, we can keep that level of cost going forward.
As I mentioned, our electricity costs are actually down quarter-to-quarter. And so I think – and chemical costs are just essentially flat or up miniscule percentage points.
So I think that’s the type of thing we should continue, but realizing as we continue to drill more horizontal wells and they become a bigger part of the total production mix, the corporate numbers on average come down. So speaking of corporate percentages, we benefit in this case, where we contribute more and more of this cheaper horizontal operating cost.
Brian Singer
That’s great. Thank you.
And then my follow-up is, with regards to the Jo Mill disclosure here, you talked about $6 million per well for a 10,000-foot lateral. You talked about EUR of 900,000, the BOE at a 6,800 foot laterals.
We’re trying to gross up to get you an EUR for a 10,000-foot lateral. Is it apples-to-apples of just gross it up for the increased lateral length, or is there some offsets?
And then can you talk about how the Jo Mill would compete at these economics?
Tim Dove
Well, first of all, it has a tremendous advantage to start with big shallower, and that $6 million, $6.5 million number is the result of that. As you look forward and you say, okay, let’s go from 6,500 feet to 10,000 feet, you’re realizing that last 3,500 feet of lateral is not nearly as expensive as the first 6,500 on a per foot basis.
So actually, you get incrementally substantial improvements in efficiencies, capital efficiencies as you get to the point where you’re lengthening lateral. And we’ve never seen a case where going from, say, 6,500-foot laterals to 10,000-foot laterals hasn’t been linear essentially, which is what you expect from a physics standpoint that to the extent you’re not getting impacts on hydraulics, which we don’t expect you will at 10,000 feet, but you should have a linear benefit in terms of EUR that comes from longer laterals.
And so I think the answer is, one way to look at it, we’re going to be even more impressed with the efficiencies and the economics of Jo Mill. And to the point where I think it’s going to be – it has the potential to be right at the top of the seriatim of our drilling campaign.
Brian Singer
Great, thanks. Why not a more than limited appraisal, then?
Or you just take it month by month there?
Tim Dove
Well, we’re showing 5 wells. I mean, we have, I think, a total of like 5 or 7 more this year.
Is that’s right, Joey?
Joey Hall
We have a total of 6 more. We’ve done a total of 12.
But I would just echo Tim’s comments, but even more importantly, just keep in mind that those were version 1.0 and 2.0 completions. And for our wells going forward, we do have some larger completions plans.
So our perspective on Jo Mill is nothing but getting better. So we’re very encouraged about Jo Mill, going forward.
But we’re just really in the infancy of understanding the Jo Mill. It’s a totally different reservoir than everywhere else we’re drilling and we’re just in the infancy right now.
Brian Singer
Thank you.
Operator
We’ll take our next question from Doug Leggate with Bank of America Merrill Lynch.
Doug Leggate
Thanks. Good morning, Tim.
Good morning, everybody. I guess, Tim, thanks for all the color on trying to explain what’s happening with the oil cut.
But I guess one of the things that we weren’t aware of ahead in the quarter was Targa had go on this plant, that was mothballed 45 million a day, I think. I’m just wondering, they’re talking about additional debottlenecking, additional plants coming online.
I’m just wondering, are we going to see any more of this in terms of incremental expansion of your gas and NGL recoveries as we go through this year based on what you know at this point?
Tim Dove
Doug, what I would say is that we should see a continuing focus, and they’ve done a tremendous job on things we can control this year. And in particular, that has to do with what’s decided on NGL recoveries.
As Rich mentioned, the yield in April, we’ve seen a little bit of weakness on NGL prices. So we’ll have to see where we get to there.
But there’s no reason for us not to continue to look for ways to reduce line pressures. That’s been one of the very material benefits of, number one bringing on that plant; and number two, doing the looping and the compression work we’ve done.
That can still continue. So I would anticipate, and this is one of the reasons we think the total gas and the mix goes up, that we’re going to still benefit this year.
But I think more importantly, next year, as Targa actually brings on 2 new facilities, one in the first quarter and one in the third quarter, is our current understanding, then not only will we be increasing capacity, but again, it’s state-of-the-art capacity, higher NGL cuts. And you’ll have the ancillary effect with the compression of the plants to, again, reduce line pressures.
So I only see good things when it comes to our ability to increase gas and NGLs going forward and realizing it’s a bit of a byproduct of what we do when we’re drilling oil wells. But shoot, its positive cash flow, and we’ll take it.
Doug Leggate
Forgive me for the follow-up on that question, Tim, but just help me be a little stupid here for a minute. So the growth rate for oil hasn’t changed, but the percentage has gone down.
But the full year guidance for BOE production hasn’t changed either. What am I missing?
It seems like the BOE number needs to go higher for that math to work.
Tim Dove
Well, Doug, we’ve put a range in terms of production, as you know. We have a tendency to be conservative.
We’re not, at this point, at a position where we’d say definitively that we want to change the production guidance, but you’re certainly on to something when it comes to the fact that on the first case, our first quarter production exceeded our forecast. I think, the real proof’s in the pudding here as we get out of the second half of the year, where we, as Joey mentioned, we’ll be in the 70 to 80 POP range for each of last 2 quarters.
We’ve actually popped that many wells if you look back to our history a couple of different quarters in the past. So we have a full capability of doing that.
But we’re conservative, Doug, is the answer. And I think, what we’re saying is, our oil numbers look like good.
Maybe our gas and NGL numbers can exceed.
Doug Leggate
I appreciate that. And I guess, it’s the final follow-up for me.
So obviously, you’ve got back-end-loaded POPs in the second quarter. Can you give us some – I don’t know if you could normalize that to say what would be the equivalent average wells online in Q2 as kind of this number to help up a little bit?
Because I think, some folks out there thought your Q2 guidance is light or low at pretty much your graphic that you’d put up on the last quarter. So any help there would be appreciated.
Tim Dove
Well, we’ll have to get back to you on that specific question to see if we can normalize it. But, I mean, I think the bottom line is – I’ll give you an example in the first quarter.
We only popped 3 wells in January. Similarly, in April – Joey, how many wells are we going to pop in April, for instance?
Joey Hall
[indiscernible]
Tim Dove
Its 10 wells, so out of a total 60 or 65, so when we say back weighted, we’re not kidding. We’re going to have a lot of POPs in both May and June to catch up to that 60 to 65 number.
So normalizing that is a sort of – it’s going to be a difficult thing to do. But I think the way that and – Frank, if you can back to Doug with some concept ahead to normalize that, that will be helpful.
Frank Hopkins
Yes, I mean, Doug, even not to show you how complicated it is, but it is. If I have a POP in May, there’s a lot of difference between one on May 2 in May 30th, or May 31st.
So – and all those things are play into it.
Doug Leggate
Kind of April is helpful enough guys. Thanks a lot.
Tim Dove
Right.
Operator
We’ll take our next question from Charles Meade with Johnson Rice.
Charles Meade
Good morning, Tim and to the rest of your team there. I wanted to ask if you could perhaps – and this might be for Chris, if you could perhaps elaborate a bit more on some of these technology initiatives that you have.
And really, what I’m curious about is if you could maybe talk about which of these initiatives are going to be – are going to have the biggest near-term impact? And then maybe in contrast to that, maybe not, but which ones are more critical for you delivering on this 10-year path that you have?
Chris Cheatwood
Yes, Charles, it’s – I’ll tell you that the biggest thing is not technology themselves, but it’s the change in the way we work. Because right now, we produce 250,000 BOEs a day.
We’re going to 1 million. We have 3,600 employees.
We’re not going to have 15,000 employees when we get to 1 million in 10. So all of these technologies kind of add up to be, what we call, people multipliers, work multipliers, however you want to look at it.
But I’ll single out a couple of them that I think are going to be – well, obviously, the automation, I think, can really help us in that area, reducing field visits, things like that. But you noticed, I spend a little time on the drilling system.
I think that one is just going to be huge for us. And to kind of describe, because I figured that we’d get this question this morning.
Really, what we’re building is like a traction control system for your car. We’re always trying to drill wells faster, live out there on the edge, so we can reduce the drill times.
But often, we push it past the edge and we produce nonproductive time, a.k.a. like a train wreck well.
Well, what we’re trying to build here is a system, where we can – it’s like pushing the traction control button on your car that keeps you from sliding off in the ditch if it’s an icy day or something like that. But what’s even more exciting about this is with the capabilities of machine learning, not only are we going to go to a level of prediction to get a warning, we’re going to get to a level of prescriptive analytics, where it’s going to be telling us what to do.
And ultimately, the artificial – as it learns over wells and number of wells and number of feed, will be to a point where it’s actually artificial intelligence that’s drilling our wells for us, with us observing. And what that’s going to do is just narrow the outcomes on these wells.
So instead of, hey, we drilled a record well for $3.5 million and then we have a train wreck that’s $8 million, we’ll start narrowing in on, hey, we’re averaging around $4.5 million or something like that for drilling a well. So that kind of gives you a glimpse of what we’re after there.
Charles Meade
Yes, Chris, that’s a good metaphor with the traction control and really a great vision. I guess, it’s going to take you guys – hopefully, you’ll get there sooner than later, but I appreciate the color.
Chris Cheatwood
We’ve got it running right now, so – not their artificial intelligence, but we’ve got the predictive analytics right now.
Tim Dove
And Charles, one way to think about it is every 1% of NPT, nonproductive time, if you look at the $2.5 billion capital budgets, we’re at $25 million. Every time you can move 1% lower on NPT, it’s big money, especially if you can do it at several percent.
Charles Meade
Got it. And then, my follow-up is, I think I’d probably – hopefully this is a little simpler.
The Jo Mill, should we think about the emergence of this zone as a target as replacing, possibly replacing some of your Lower Spraberry or Middle Spraberry inventory? Is this all going to be additive to that?
Tim Dove
I think it’s part of – it’s actually, we’re doing, Charles, what I’d call increasing the size of the pie. So it’s not – we’re not looking at the same pie and divvying it now to more Jo Mill.
We’re increasing the size of the pie. So we love the Lower Spraberry Shale.
We’re liking and loving the Jo Mill even more. You know where we are in Wolfcamp B and Wolfcamp A.
We’re actually drilling Wolfcamp D well this year. We’re drilling a Clearfork well in Midland County this year.
The pie is getting bigger is the way to think about it, and Jo Mill is going to be a big slice, I guess, is the way to think about it. And I think, for that matter, we haven’t even got much data yet in on the Middle Spraberry shale.
And also, as we’ve discussed on the road with a lot of our investors, you look at Parsley’s success with one well in the Wolfcamp C, and that clarifies for us hundreds of locations in Wolfcamp C in the same area. So the pie is getting bigger.
I don’t think the pie is getting split differently.
Charles Meade
Got it, thanks.
Chris Cheatwood
Charles, let me just add, too. I think, go back a couple of years, we started with the B.
That was basically all we were doing. Then we added the A, and when we got comfortable with the A, we put a lot more As in the mix.
And the same thing with Lower Spraberry Shale, that’s where we are with Jo Mill now.
Charles Meade
Got it, thank you, Frank.
Operator
We’ll take our next question from Evan Calio with Morgan Stanley.
Evan Calio
Hey, good morning guys. Let me just go back to the [indiscernible] next question one more time.
Are you guys assuming that the line pressure benefits unwind to underpin that long-term guidance? Or where is it – is it a higher EUR I think, that Doug referenced?
And maybe secondly, how do you manage the increase in GORs, over time, that you reference as a production profile matures, to support the long-term guide, at least the number you’ve got on 2026?
Tim Dove
Yes, the way to think about the long-term EURs as they’re affected by gas-oil ratios is that a well that might come on at 75% or 70% oil – 77% oil would probably make 70% oil in its life, which means that the gas-oil ratio does go up through time. But that’s just is what it is.
That is the nature of the reservoir when pressures are reduced through time and you get below double point, and as a result, you release more gas in the system. It just is what it is.
So what that just simply means in our case is, is that we’re going to need more gas processing capability, more NGL processing capability and more pipelines to move those volumes. But I don’t think it’s anything other than what it is, and we’ve seen it, like I said, for decades in the vertical drilling campaigns of the Permian Basin.
When it comes to the oil mix, the oil mix, I think, is certainly going to be affected by the fact that I think we’re going to be successful in continuing to boost our gas and NGL production just because of attention to detail in the field. We’re certainly not saying anything about our oil production of our wells.
The wells are coming in great, they’re coming in on prognosis and it’s actually better when you start considering 3.0. I’m hopeful, even better when you start considering the tests that are in excess of 3.0.
So what you have is a lot of moving parts here, but I think they’re all moving in the same direction, which is up into the right.
Evan Calio
You stepped in the east – you stepped east in Glasscock this quarter – did that have any effect to the NGL gas mix?
Tim Dove
No.
Evan Calio
The second question, if I could, the 3.0 completion performance in the northern area of Lower Spraberry is new and you’re significantly outperforming your main bell type curve with fairly long production history here, clearly long in the 24-hour IPs with some others. When do you think you have enough data to realize that curve?
Joey Hall
So as we characterize, and we talked a lot about kind of where we are in all the development of all of our reservoirs. The Jo Mill is in the first inning.
The A’s and B’s are getting into later innings, and I would say the Lower Spraberry Shales are kind of in the middle. We just recently started doing some of the larger completions on Lower Spraberry Shale and we have some more plans this year, where we’re also testing some spacing.
But I would say, we’re lagging behind A and B just because we haven’t drilled as many wells and we’ve started the version 3.0 completions later. So I’d say we need another six months to a year under our belt before we have the same handle on those as we do on our As and Bs.
Evan Calio
Great. And I guess, just squeeze in another set of general question in kind of the spirit of the tape here.
I know you guys are very well hedged now in 2017, close to zero net debt, some asset sales planned. Yet, I mean, is there an oil price, over time, in 2017 where you reexamine your 2017 program?
I leave it there.
Tim Dove
I don’t think so, Evan. We’re running 18 rigs.
We’re going to run them through the end of the year, as has been telegraphed and very much localized, we’re not going to change the RPMs of the engine midstream. We’re going to keep running.
We’re going to hit this year’s targets. We’ll evaluate next year.
I think that next time we really need rigs to keep at a 15% growth rate is next year. We’re just going to keep cranking out our plan.
Evan Calio
Got it. Thanks guys.
Operator
We’ll take our next question from Michael Hall with Heikkinen Energy Advisors.
Michael Hall
Good morning thanks. I’m just kind of curious on your perspective on the export market, actually.
You guys are a leader in helping open that up and have taken some barrels off the U.S. market.
It sounds like you’ve planned to continue to press on that. How do you see that playing out for Pioneer, but also broadly, over the coming year?
And are you aware of any physical constraints on the ability to export at the Gulf?
Tim Dove
Yes. Thanks, Michael.
I really am confident in this. This area of the business is going to be expanding rapidly as we go through time.
If you look back, really, over the last few months, this is just a developing market scenario, and it’s developing to the point where there’s cargoes going to various different places. So for example, in the February-March time frame, the biggest importer of our crude oil out of United States was China, and that’s significant because of all the additional refining capacity that’s been put into China, and they can take anything in terms of quality.
So we really think China has a lot of potential. But if you look at, as I mentioned, the cargoes that are going to out in the second quarter, they’re going to, in this case, Wales on the one hand, Italy on the other.
And then we’ve had cargoes in the past going to Canada and Venezuela. So what you’re seeing is a burgeoning world market, looking for the style of U.S.
crude that basically is excellent across generations of transportation fuels. It’s very high-quality oil.
And as we look forward, and in particular, over the next several years, we’re going to be exporting hundreds of thousands of barrels and maybe many millions of barrels a day from the United States as we just process the Permian growth plan, which is going to be mostly all this light sweet oil. Today, there are new facilities being built on the Gulf Coast as we speak.
There are export volumes being moved to course you out of Corpus Christi. We’re actually looking at moving volumes into some of the domestic markets, but some can be exported in areas north of there, out of Houston, for example.
So there’s really going to be a lot of opportunities for this business to really dramatically increase in terms of scale and scope. It’s going to make the United States a geopolitical power when it comes to energy.
There’s no doubt about it. And you can make a case, we’re going to be one of the main exporters, and the world is looking for us for sources of supply that are on the one hand, high-quality oil, but also secure.
As you know, the Middle East has controlled a lot of the Far-Eastern supply for a long time and Far Eastern countries are interested in taking more secure supplies than have to go through this trader moves. So, therefore, I think, we have a big advantage, going forward.
And as those facilities are developed, we have more VLCCs going there. So; I really see, and I’m expecting big things here.
Michael Hall
That’s helpful color. It seems like a pretty intriguing dynamic.
I guess, also then, at the more micro level, I’m just curious on these 15-well testing, kind of this next step-up in completion intensity and other design changes. What would you kind of say a threshold for successes as it relates to what sort of outperformance you’d want to see versus the established Version 3.0?
And what kind of time frame are we realistically contemplating?
Tim Dove
First of all, various tests and various zones is the way to capture it. We’ve got some 2,500-foot laterals and 3,000-foot laterals tests that are both in the Wolfcamp B and Lower Spraberry Shales.
We’ve got 3,000-foot tests also in various counties. So there was – it’s just spread across the acreage.
In one particular case, as I mentioned, we have a 5,000-foot – 5,000 pounds per foot job happening in an area, in a particular pad, where we have short laterals. The objective is can we POP 5,000 pound per foot and create a situation where the economics are just as good and try to mimic of the economics of the 10,000-foot lateral.
Those are all underway. We expect the POPs in those cases to be spread.
A lot of them will come in the second quarter, but several will come through the year. But we’ll be able to talk more about this.
We’ll probably have some color on this even during our call during August, talk about some of these results. But to answer your question as to what we would expect, as we went from 1.0 to 2.0 to 3.0, we see pretty significant increases.
I would say, in general, it would be in the neighborhood of 20% to 30% bumps in EURs, so that would be a target. If we can do that again, we think that will cover easily the cost of increasing the size of the completions.
So if you ask me what’s the target, that would be a great target.
Michael Hall
Thanks, very helpful. Congrats.
Operator
And we’ll take our next question from John Freeman with Raymond James.
John Freeman
Hi, guys.
Tim Dove
Hello, John.
John Freeman
Obviously, the vertical integration and the big infrastructure footprint that you have guided and continue expanding has been definitely distinct advantage. And I know that right now, you are just sort of running that $300 million infrastructure spend, basically constant in the model in the next several years.
I’m just trying to get an idea of kind of how you all thinking about the trade-off of when you want to build out your own infrastructure versus kind of bringing partners in for either a portion or all of the project, either for financial reasons or just to accelerate the buildout?
Tim Dove
Yes, it’s a great question. I think, first of all, it somewhat depends on what business we’re talking about because if you’re talking about the water business, for instance, we are executing that ourselves and we’re well into it, as you know.
Through time, and in particular, in next couple of years, we’re going to bringing on the Midland Water. We’re building that facility ourselves to further their processing capability for the city of Midland.
And then in exchange for that, of course, we get well priced – low-priced water to capture our capital cost in that project. But as you go forward, and you’re past 2018, we will need to continue to build subsystems and frac ponds so on and associate with that are processing because we’re going to need to be processing and cleaning up some water for frac quality rather than reinjecting it, we might as well use it in fracs.
And so those costs will continue as part of the $300 million per year. When you start thinking about sand, it could be more chunky.
We’ve got a need for expansion of our sand business, and probably, we’ll make a decision on the end of this year for 2019 sand. And as from the today’s volumes, there would actually be a tripling of the sand volumes coming out of Brady.
And so we want to execute that, too, and get it done. And we have the engineering already done and we’re going to process that thing.
Today, on gas processing, and as you know, we already have a partner, and Targa, as I said, has done a wonderful job of working with us to improve our fuel deals, and I see that continuing as a partnership. So for the current time, until we build all this stuff out, I don’t really see a need for a partner.
We can do it within own our capital wherewithal. We want to make sure it gets done pursuant to our specs and our requirements on time.
We don’t want these things to be an impediment to our ability to execute. So we are going to build them.
We’re going to operate them. There’s other alternatives from a capital market standpoint in the future.
We’re well aware of those, and we’ll evaluate those when the time comes. But for the time being, we are building our stuff to make sure it’s ready when we need it.
John Freeman
Great, I appreciate the color. And just following up on a comment that you made earlier, Tim, about basically increasing the size of the pie as your activity continues to delineate additional zones and locations and you basically expand the inventory organically.
Would these bite-sized sort of divestitures that we’re sort of seeing here in the Permian recently, should we just sort of think about that as that’s just going to become a normal course of business as you’re kind of managing your inventory when certain areas start falling further back in the queue in the Permian as you kind of expand other areas?
Chris Cheatwood
John, this is Chris. Yes, it’s a possibility, but I will tell you that we don’t have a lot of, I’ll call it, fringing areas that are obvious divestiture candidates.
So you’re starting to cut some pretty good meat if we’re going to have many more divestitures. And also, as you can see, we’re getting smarter.
We’re drilling cheaper. We’re making higher productivity wells.
We expect that trend to continue. So really understanding what the value as some of these properties are in the not-too-distant future is still up in the air.
So I’d have to say, I don’t think you’re going to see a whole lot of that, I mean your spend in the base model, going forward.
Tim Dove
Yes, I think, the way to sort of complement what you said is that we have multi-decades of inventory, which means there’s not a lot of value, perhaps ascribed, to the last set of decades that are in that inventory. So it is a very elegant source of capital if we were to ever need it.
But as you know, going forward, our model is to not need additional capital. So our model is to spend within our cash flow and generate free cash flow.
So although there is a tremendous amount of value that could be unleashed from those assets and that acreage, well, on the basis, our model doesn’t suggest we’re going to need to tap that.
John Freeman
I appreciate it. Thanks, guys.
Operator
We’ll take our next question from Bob Morris with Citi. [Operator Instructions] Bob check the mute function.
We’ll take our next question from Neal Dingmann with SunTrust.
Neal Dingmann
Sorry, guys. Can you hear me?
Tim Dove
Yes, we can.
Neal Dingmann
Can you guys just talk about, it looks like on the water spend, it was about $300 million last year versus the $160 million this year going forward. What do you anticipate on that?
Tim Dove
Yes, actually, we saw on that slide was $300 million project to date, so over the last several years. This year, we’re spending $160 million.
Next year, the plan is $150 million, and that will incorporate, as I mentioned, the construction of the Midland processing facility. At that point in time, I think on a per annum basis, the number goes down considerably.
But for this year and next year, we’ve got to build the main system. Really, the backbone pipeline of the system is 100-mile pipeline.
Finishing that this year is imperative. At which point, then the Midland system becomes imperative to add, as Joey mentioned, 240,000 barrels a day of more effluent water.
And at that point in time, you’d get in, generally speaking, in the world of just building incremental subsystems and frac ponds where you have the activities. So I see that number going down on annual basis in the future after 2018.
Neal Dingmann
Great, thanks.
Operator
We’ll take our next question from Jeffrey Campbell with Tuohy Brothers.
Jeffrey Campbell
Good morning and congratulations on the quarter. On water investment, all the cost savings are – certainly should be ignored, is it fair to see your water effort is necessary to secure the life for future growth?
In other words, is it an important exercise of risk management?
Tim Dove
I will leave it this way. Water is perhaps the most misunderstood and undervalued aspect of the impediments that the industry could face.
As Joey said, we are today sourcing 350,000 barrels a day. If nothing changes to how we do with, how we do things 10 years from now, that’s a 1.4 million barrels a day.
Today, we represent 8% of the Permian rig count. So when you start doing the math, you realize, oh my gosh, we’re in a difficult situation to be able to source that kind of water, which means we’re going to have to go, as I mentioned, more towards the recycling of produced water that also comes back to us after the frac.
And so that has to be in our thoughts, long term. But I think being ahead of this is tantamount to substantial risk avoidance going forward.
And we are just not going to be put in a position where we have that kind of impediment that’s unsolvable. We are solving it ourselves.
Jeffrey Campbell
Okay, great. Thank you.
Slide 12 shows that the Jo Mill drilling is taking place in both the northern and the southern acreage. Today, are you seeing any more favorable results in one area versus the other?
And are there any significant portions of your acreage where you don’t anticipate the Jo Mill to be viable?
Joey Hall
Yes, Jeff, no, we’re seeing good results all over. As a matter of fact, when you go back historically, some of our best Jo Mill wells have been drilled in the southern part of our acreage, and then some of the better ones that you see here on this illustration are in the northern part, central part.
So we’re seeing good results across the entire acreage position.
Tim Dove
Yes, the way I’d catch that, just to add, is that if you look back to the vertical drilling campaigns over the last several decades, every single one of those well is essentially completed in the Jo Mill. The Jo Mill is ubiquitous across the whole play, basically, just like the Midland and Lower Spraberry, to a great extent.
So it may be slightly better in some areas, but the point is, you have Jo Mill that was being completed in all the vertical wells in the history.
Jeffrey Campbell
Okay, so massive well control on the Jo Mill. If I could ask one last one real quick.
Just to clarify, are your exports entirely black oil? Or do they also include some condensate?
And if that’s the case, is there a predictable mix.
Joey Hall
They’re all black oil. They’re all...
Tim Dove
All WTI.
Joey Hall
WTI, West Texas crude.
Jeffrey Campbell
Okay, great. Thank you.
Operator
And we’ll take our next question from Phillip Jungwirth with BMO Capital Markets.
Phillip Jungwirth
Thanks, good morning. You guys have been checking all the boxes, really, in terms of what’s needed to achieve the 10-year plan.
I’m curious as to whether you think, from transportation, both oil and reside gas, will be needed in the future for Pioneer, given the positive production growth revision for the industry we continue to see out of the Permian Basin?
Tim Dove
Well, first of all, if you’ve been following us, you know we already have 3 different evidence from transportation as we started up the process. But just for a full disclosure, we are looking at further FT commitments for oil that would cover us probably well into the middle part of the next decade.
Can’t give any details on those because they’re involved with detailed negotiations now. But I can assure you, we are all over that and we will have it solved at least to the middle of the next decade within a short period of time.
On the gas side, we’re encouraged by the fact that 2 big MLP pipeline producers have announced the construction of greenfield pipelines going from Waja, which is in the Permian Basin, to Agua Dulce, outside of Corpus Christi. That will allow us to swing gas to Mexico into the Mexican market and actually grow further, or through the LNG export markets or for that matter, to Henry hub and then swing it into U.S.
market. Those pipelines will be ready in a couple of years.
And so accordingly, we do not see any significant bottlenecks on the pipeline arena on any of these commodities, including crude oil and natural gas and natural gas liquids. We are in good shape.
Again, we need to complete some FTE negotiations on crude oil. And in that case, we will be in good shape through mid of the next decade.
So I think we’ve got that well under control.
Phillip Jungwirth
Okay, great. And then as you guys continue to drill higher-return, lower F&D well and spring – down throughout the 10-year plan, do you have a sense as to when you could get to a double-digit corporate return on capital employed, say, at $55?
Tim Dove
I think the way to look at that is there’s an inertia that’s associated with all the capital investment we’ve done over the last couple of decades that has to be considered. And so what we’re looking at doing is improving from where we are today.
And if you look at the math, just with capital we’ll be spending over the last several years, we can add, probably add an increment, say, 2% to 3% per year at the bottom line when you’re competing at on ROE or ROCE each year, after a few years, you’re there actually. Actually, you’re there at double-digit ROCE and ROE numbers, just owing to the fact that your drilling as you mentioned high return wells.
Phillip Jungwirth
Great, thanks.
Operator
We’ll take our final question from Scott Hanold with RBC Capital Markets.
Scott Hanold
Hey, thanks. I appreciate it.
I know it’s been a long call so far, so I’ll try to keep to one. And Tim, you all have obviously been deliberately increasing concentrations and intensity of the fries that have been on your wells.
When do you think is the at which you can step back and say, okay, we understand whether we need to go to 5,000 pounds or a whole back to 3,000 pounds on formation X, but formation Y, we’re going to do this. I mean is, that something that is still a few years away?
Or do you think you can accomplish that in, say, see next 12 to 18 months?
Tim Dove
Well, I think you have to look at it along the lines of each zone, right? Each zone is a question mark because we’re testing various different zones.
But in particular, when it comes to the version past 3.0, most of those are still focused on Wolfcamp B. Actually, I mentioned there’s going to be 3 wells that are going to be – of that, that are going to be drilled in the Lower Spraberry Shale.
So we will have done a lot of post 3.0 fracs on other zones other than the Wolfcamp B this year. That will tell something about Wolfcamp B.
But I think, what this is going to be in the fullness of time that we test the bigger fracs across spectrum. Like Joey mentioned, even in the Jo Mill, you’re seeing good well performance, but a lot of that was a lot of Version 1.0 and 2.0 wells.
And so even in the Jo Mill, we’re going to have to see how these 3.0 fracs do and then further to that, as we go past 3.0. But I think it’s going to take a long time and take many moves to get to the point where we really understand where we get diminishing returns.
Also, that’s when you cutoff point is, right, when you realized, oh, we popped 3,500 pounds of sand per foot and you did just as well as 3,000, so you’re going to call it a day there. The other factor that’s involved, of course, is the more we POP, the more logistics we encounter in terms of the strengths of the system, whether it’s for water, sand, what have you.
It always has to be considered. So it’s really – but really, what it all comes down to fruition is when do we see diminishing returns?
We won’t know that in several zones for many more years.
Scott Hanold
Okay. I appreciate that.
Thank you.
Tim Dove
Well, thanks for everybody on the call. Sorry, it’s taken so long.
But hopefully, we have some interesting new things to talk to you about. I hope everybody enjoys your last part of your spring and your summer, and we’ll be seeing you on the road in a few events coming up during the rest of May and June, and then we’ll be talking to you again in August.
Thanks very much.
Operator
This does conclude today’s conference call. Thank you all for your participation.
You may now disconnect.