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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good day, ladies and gentlemen. Welcome to Pioneer Natural Resources' Third Quarter Conference Call. Joining us today will be Tim Dove, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; and Neal Shah, 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 web site, 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 December 2, 2018. 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 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 Vice President of Investor Relations, Neal Shah. Please go ahead, sir.
Thank you, Greg. Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Tim will be up first. He will provide the financial and operating highlights for the third quarter of 2018, a strong quarter of execution for Pioneer, and our latest outlook for the remainder of the year.
After Tim concludes his remarks, Joey will review our strong horizontal well performance in the Permian Basin, including our recent successful Stackberry appraisal results.
Rich will then update you on our firm transportation commitments to move oil from the Midland to the Gulf Coast and the financial benefits we are receiving. Rich will also cover the third quarter financials and provide earnings guidance for the fourth quarter.
Tim will then return with a brief recap and general commentary on 2019. After that, we will open up the call for your questions. Thank you.
So with that, I'll turn it over to Tim.
Thanks a lot, Neal. On any objective measure, the third quarter was an exceptionally strong quarter for Pioneer. We substantially beat consensus on earnings and EBITDA. And cash flow for the quarter exceeded our capital spending, all of which are huge positives for PXD.
Earnings were very robust at $355 million on an adjusted basis or $2.07 per diluted share.
Total Permian production met the top-end of the range that we had provided for the quarter. And importantly, Permian oil production exceeded the top-end of the range, growing by 7% quarter over quarter.
Due to that exceptionally strong execution during the quarter, the number of wells that we put on production exceeded our estimates, where we placed 69 horizontal wells on production. And as a result, the balance sheet remains very strong with significant cash on hand and very low debt statistics. And in fact, net debt was reduced by $200 million this year – this quarter on a quarter-to-quarter basis.
Turning to slide 4. The company continues to benefit from its long-term planning approach and particularly regarding our FT program for oil deliveries to the high priced Gulf Coast and export markets. And for the quarter, that benefit resulted in about $200 million of incremental cash flow for the third quarter.
The number is expected to come down to about $125 million in the fourth quarter. That's simply a product of the differentials having tightened in the fourth quarter as compared to those numbers in the third quarter.
We're still continuing to deliver quite a large volume of oil to the Gulf Coast, about 165,000 BOE a day – or barrels of oil per day in the third quarter under those same FT contracts. And about 130,000 BOPD were exported.
Those numbers will be increasing. In fact, our FT capacity goes up beginning of November to 185,000 barrels of oil per day and over 200,000 [BOPD] in early 2019. So this will become an even bigger part of our results as we move forward. And we continue to see the benefits of incremental pricing as a result.
One of the things we've then seen is that about 90% of these volumes – over 90% of our volumes will be on FT contracts. And those receive Brent-related pricing, so that's a tremendous positive for the company.
And as we discussed on our last call for the second quarter, we have no exposure today for Midland oil pricing through 2020. That kicked in really in September.
Similarly on natural gas, the company has benefited greatly from FT to western markets, where we receive an uplift of about $1 per Mcf versus that as if we had left the gas into Waha, into Waha sales areas for the whole third quarter.
And from an operational standpoint, Joey will cover this in a lot more detail, but the results look very promising for our first Stackberry pad. You may recall we're drilling a total of three sets of these pads, the first of which we're reporting on today.
The objective of course is to determine how to optimally space and stagger and sequence the Middle Spraberry Shales, the Jo Mill, and the Lower Spraberry Shale intervals for longer-term development. Of course we've drilled wells in all these zones, and they've been excellent wells. And now we're proving we can drill even better wells as we stagger and space these properly.
The idea is to continue to add significant returns as we incrementally go into development mode on the wells. And we're not facing, as a result, any sort of parent/child issues. In fact, to the contrary, we're actually making better wells.
So the idea here is to not be drilling wells in a situation where we're just simply adding low return downspace wells that essentially over capitalize a given rock volume. We're focused on incremental high returns on each individual well.
Going to slide 5 then. As we reported in the second quarter call, we will soon add two rigs in December that are focused really more or less on 2019 production impact, since we're just coming here at the end of the year. For this year 2018, we still expect the POP range to be 250 to 275 wells.
Margins look very strong. The IRRs continue to be at very high levels, especially when you consider the FT uplifts that I mentioned a minute ago.
We're still on track to place 60 Version 3.0+ wells online for the second half of this year. Fortunately, we completed 44 of those and placed 39 of them on production in the third quarter. Joey will show you more details on that. But the results look really phenomenal, as we have gotten to a point, we think we've reached an optimal place when it comes to these high volume completions.
We also reported in mid-September that we've entered into a long-term West Texas supply agreement for sand with U.S. Silica. It'll represent 30% to 40% of our sand supplies when this kicks in in the first quarter of 2019, at roughly half the cost of our average current supply of sand. As we continue to look at the benefits of reducing sand costs, you can have very dramatic improvements on our well economics, as we drop the cost of those wells related to the sand volumes.
Then going to slide 6, as an update on the divestiture process. We're pleased to have announced that we closed on several sales earlier this year. But we've also most recently, a week ago, announced the signing of a purchase and sale agreement regarding our remaining South Texas oil assets – we refer to them as the Sinor Nest assets – for a net $132 million. That should close in the first half of December. We continue to make progress on the divestiture of our remaining Eagle Ford assets as well.
The 2018 capital program remains at about $3.4 billion. In essence what that is, is spending our operating cash flow. So $3.4 billion is the current estimate of our operating cash flow for this year. And that will also be funded if needed from asset divestitures. But in other words, we expect 2018, for in a year's sense, to be essentially cash flow neutral at year end, which is a great step in the right direction.
And 2018 production trajectory looks essentially the same as it has been, which is in the 19% to 24% range, trending towards the upper half of that range.
For the first time, we're talking about our returns on capital employed. You will see in this slide here that we're focusing on an ROCE number expected to be above 10% for the year. That was about 4% last year. What this is, is reflecting the impact of our high return D&C program. We have very high returns at the drilling and completion level, and those then positively impact the bottom line. It's what you would expect.
Also on a per share basis, the company reporting very strong numbers. And we're not issuing shares in connection with large transactions that basically dilute your per share metric. So our per share metrics will be exceedingly strong. Our ROCE will be exceedingly strong as well for 2018.
Finally, on the rainbow chart to the bottom right, this is something we've had in for maybe a decade or so. But we've now adjusted this to be Brent oil price-related. We are now essentially a Brent-priced company, if you talk about our oil sales. And so the rainbow chart has been adjusted to reflect Brent as being the key oil price sensitivity. So just make a note of that for the future.
Now going to slide 7. Production growth remains on a continuing positive trajectory. You can see that our fourth quarter guidance is shown in the right-most column for 2018, 293,000 BOE to 303,000 BOE out of Permian with oil production 188,000 BOE to 194,000 BOE. Just a continuation of the same sort of execution and growth that we have seen over multiple quarters now, and as we continue on track with 1 million [BOE] in 10 [years] goal for the future.
What I'm going to do now is pass it over to Joey. He'll give you some information on the Stackberry well results and an update on the results from our 3.0+ completion campaign for this year.
All right. Thanks, Tim, and good morning to everybody. I'm going to be picking it up on slide number 8.
And as Tim has already mentioned, our first Stackberry appraisal pad did come on line in the third quarter and is showing strong early time results. Our goal in these tests is to understand how the Spraberry zones interact with each other in full development. We're basically combining our experience from nearly 1,200 wells completed to date with a complex reservoir model that we're developing using cutting-edge science and technology, as you can see illustrated there on the bottom left.
After 90 days on production, we've seen outperformance of approximately 35% over previous Spraberry wells across all three benches in the same area. And now we're going on to gain invaluable knowledge on spacing, staggering, sequencing, and stimulation of these Spraberry zones.
Needless to say, we're extremely pleased with these early time results. And this one test alone has de-risked approximately 50,000 surrounding acres, which allows us to transition the Spraberry intervals into our development plan with confidence.
Now I'm going to be moving on to slide number 9, where you'll see a summary of the Version 3.0+ completion results. The graph on the left represents every Version 3.0+ completion POP through Q3. And we've compared them to Version 3.0 wells in similar areas across the formations.
You'll note the strong cumulative production outperformance to date of approximately 35% for the 3.0+ completions. And now the histogram in the bottom right shows the growth in the number of unique completion designs we've had over the past several years. As you can see, we've more than quadrupled the number of designs that we pump.
As an example, there are roughly 15 unique designs associated with Version 3.0+ alone. Our acreage is larger than the state of Connecticut. And it has a diverse geology over multiple horizons. And as I've stated many times in the past, one size definitely does not fit all. And that makes it impossible for us to identify our completions in just a few buckets.
Bottom line, we're focused on maximizing rate of return, and that requires a wide variety of completion designs. Overall, a very strong execution quarter for the Permian team.
And now I'll pass it on to Rich to discuss marketing.
Thanks, Joey. I'm going to start on slide 10, where you can see that Pioneer's oil marketing efforts were a key differentiator for the quarter and significantly improved our cash flow for the quarter. Specifically, the barrels that we purchased at the Midland Tank Farm and transported via our FT contracts to the Gulf Coast led to incremental cash flow of $189 million.
Looking at this on a per-barrel basis, our Gulf Coast sales was over $17 per barrel higher than the Midland prices that were in the mid-$50s.
As we look at the fourth quarter, we're expecting a cash flow uplift, as Tim talked about, related to our FT of over $125 million. It's also worth reiterating what Tim mentioned, that in November, our volumes that we transport to the Gulf Coast increased to 185,000 barrels a day from 165,000 barrels a day, and will increase in January to 200,000 barrels per day. All of these barrels are expected to receive Brent-related pricing, increasing the company's cash flow and overall cash margins.
Related to that, the company has derivatives in place now for 25,000 barrels a day of 2019 production that are tied to Brent prices. And future derivatives will also be tied to Brent prices.
Turning to slide 11 and looking at Q3 earnings. Net income attributable to common stockholders was $411 million or $2.39 per diluted share. It did include non-cash mark-to-market derivative gains of $38 million. And unusual items listed here really related to our asset divestitures, and that included a gain on the West Panhandle sale of $114 million after tax, offset by other related charges, which principally related to expensing future pipeline commitment fees related to our Raton divestiture.
So adjusting for those unusual items, we were at $355 million or $2.07 per diluted share.
Looking at the bottom of the slide, where we show Q3 guidance relative to results. You can see that all of the items are within guidance or on the positive side of guidance for the quarter. So overall, an excellent quarter for the company.
Turning to slide 12, looking at price realizations. As you can see there looking at the oil bar that oil prices for the quarter were up, including the benefits of FT contracts, by 5%. Without that benefit, and just subject to Midland pricing, we would have been down 6%. So once again, the benefit of our FT contracts.
If you look at NGLs, NGL prices were up 25% quarter-over-quarter, really reflecting the significant improvement in ethane and propane prices for the quarter. Gas prices were up 12% to $2.21 per Mcf, reflecting the benefit of moving 70% of our gas out to the Southern California markets, where it's priced on the SoCal Index. And that netted an extra dollar per Mcf relative to Waha prices in the Midland Basin.
So overall, you can see that our marketing strategy of moving our products to higher priced markets is significantly increasing cash flows and providing improved margins.
Turning to slide 13 on production costs. You can see for the quarter that they were down $1 per BOE relative to the second quarter, or 9%. This decrease is principally related to the sale of our Raton and West Panhandle assets that had higher production costs. And that's reflected in the lower price per BOE – or production cost per BOE.
Turning to slide 14. We continue to have a very strong balance sheet and excellent liquidity. As Tim mentioned, our net debt for the quarter was down $200 million relative to the second quarter. We have no near-term maturities and really are in an excellent financial position.
Turning to slide 15, Q4 guidance. A production forecast of 293,000 BOEs per day to 303,000 BOEs per day. And really if you look at the rest of the information here, that guidance is similar to prior quarter, so I won't go through that. But in summary, we had really an excellent quarter, as Tim mentioned, and we're on our way to a very strong fourth quarter.
So with that, I'll turn it back to Tim.
Thanks, Rich. And as we've discussed today, we really have had an outstanding third quarter. And we expect this momentum to continue through the fourth quarter and into 2019. It's really too early to discuss our 2019 production and capital in detail. But the roadmap for 2019 will be to continue to prosecute the 1 million [BOE] in 10 [years] plan, just as shown on the slide number 16.
We'll continue to make decisions in the best interests of our stakeholders, where we drive down costs, emphasize returns, focus on capital discipline, and take steps to more meaningfully return capital to shareholders in the next few months.
We are, in fact, working on a number of specific initiatives that we'll be announcing over the next few months that will result in material capital savings and decreased well costs going forward. You can look for some of those announcements to come in the next few weeks.
We expect that our capital budget for 2019 will come in at a point where it's below our operating cash flow. And therefore, we expect that we will generate free cash flow in 2019. We plan to have a full update on all of this in February, as has been our practice in the past. It'll be during our fourth quarter call in early February.
And with that, we'd like, Greg, for you to open up the call for any questions.
Absolutely, sir. At this time, we will pause for just a moment. And first with Citi, we have Bob Morris.
Thank you. Good quarter, gentlemen. First question is, Joey, with the cost inflation that you noted last quarter, are the Version 3.0+ well completions still running at around $9 million all-in?
Well, the incremental cost of a Version 3.0+ completion compared to our standard completion is $1 million. And I don't know that I could actually create one bucket that explains what all of our well costs are, because it varies across the Lower Spraberry, Jo Mill, Wolfcamp A, and Wolfcamp B, and also by geographic area. But in essence, the Version 3.0+ completion still costs about $1 million more per well.
Okay. And then separately, last quarter you mentioned that the higher line pressure on Targa would impact production in Q3 by 2,000 BOE to 3,000 BOE per day. Did that end up actually being the case? And as we look at Q4, if so, is that something that's been resolved? That you'll get that incremental production back here in Q4? Or how did that play out?
Yeah, I think – are you talking about – Bob, are you talking about the new plant addition, dropping the line pressure?
Yes.
(20:36)
You mentioned it might impact Q3 production by 2 MBOE to 3 MBOE per day. And I didn't see any comment or reference to that in this release.
Yeah.
So I didn't know if that ended up happening or not.
Yeah. That's exactly right. We didn't put it in because, just in the interest of time. But the plant did start receiving gas, the plant in question, and is a Targa-related facility the last week in September. And it has significantly reduced line pressures in the area, which is a huge positive on all of our flow rates.
And I think from that standpoint, we'll continue to see the benefits of that as we get through the fourth quarter.
The next Targa facility comes online in late February. Actually in the winter period of time, there's less issues related to line pressure, simply because we use gas for the heater treater systems to make sure the oil is flowing in the colder weather period.
So we think we're in good shape. The next plant comes on, as I said, in late February. We'll continue to see the benefits of lower line pressures.
Okay. Great. That's great. Again, good quarter. Thanks.
Thank you, Bob.
Next up, we have Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, everybody. Tim, I wonder if I could pick up on your last comment about generating free cash flow in 2019. The hedge book right now looks fairly light. I'm just curious if you can put some caveats around that in terms of your commodity assumptions? And given your balance sheet strength, how would you think about the use of free cash as you go forward? Because it does look like you're getting pretty close to an inflection point.
Well I think we clearly are. The way I would catch it, Doug, we're sort of at an inflection point this quarter. This is a quarter where we actually generated free cash flow. So I think 2019 from an annual standpoint will certainly be that same situation.
Our assumptions in terms of when we refer to our current view of the budget in terms of capital and the resulting aspects of production growth and cash flow generation are based on high-60s Brent. Of course, depending upon what your view on the WTI/Brent differential, what those views are, it could be low 60s WTI or to mid-60s WTI. And from that standpoint, we think that's a reasonable price basis to go into looking at a budgeting cycle.
Now of course, we are relatively lowly hedged in 2019 compared to 2018. So we will be susceptible to lower prices if they were to occur. But by the same token, we have much more exposure to upward pricing as well.
I'm just curious, do you plan on – normally you would go into the year significantly more hedged than you are today on a rolling basis. Would you plan to step-up the hedging exposure between now and, let's say, the turn of the year?
Well, I think that's just a reflection of price. I mean if we feel like there's opportunity presented by much higher prices than we see today. You have basically a flat curve today, through 2019. So there's not a tremendous benefit above where prices are today in terms of looking out and hedging into the future.
I think we'd hold off at these kind of prices and not do much hedging. If there's an opportunity to hedge substantially higher than where we are and guarantee a significant amount of free cash flow generation, we certainly would look at it. So we're going to be flexible.
You asked the other question regarding what to do with the cash. That's something of course that we'll be looking at over the next few months. And we'll have some decisions to be made in that regard. But as I said, it's pretty clear that one of the things we're going to be doing is evaluating steps to more meaningfully return capital to shareholders.
Thanks. And I'm wondering if I could have a quick follow-up with Joey, just on the Stackberry result. Joey, if I'm looking at the chart correctly, it looks to us at least that the Stackberry initial wells are at least as good as the Version 3 Wolfcamp wells.
So I'm just wondering, how do you think about layering this into your development options, as to how you move the program forward, now that you appear to be well on your way to de-risking that inventory?
Yeah, as we stated in the – as I stated in my comments and as I stated in the slide, this basically de-risks 50,000 acres in that one particular area. And then we've – of course we have two more tests coming online. We have one that came online in October. And we're watching those results. And then we'll have another one that'll come on line here in late November. And we'll be taking that all into account.
I think it's, there's no doubt that what this does is give us confidence that we can start placing these Stackberry wells into our development plan. But I would characterize it very similarly to how I do the Wolfcamp D and other appraisals that we do.
We have such a vast array of acreage. It gives us confidence that we can start looking at how we time it and how we put it in. But how we're going to start bringing it into 2019 is still up in the air. But it gives us confidence that we can put it in at any time in this particular area. And then we'll be too early to tell on the other two areas.
Great stuff. Thanks. And let me just say I think you've drawn a line under a lot of the execution concerns of the past year, so congratulations on a great quarter.
Thanks, Doug. Appreciate that.
Moving on, from Raymond and James (sic) [Raymond James] (25:55), we have John Freeman.
Good morning, guys.
Morning, Freeman.
When I look at slide 9, I guess for, maybe first for Joey. With the significant number of the different completion designs, should we expect kind of as you learn more and more about all the various zones and the testing that you're doing that you all have highlighted, that that trend sort of continues, where we get more and more of these sort of discrete completion designs? And I'm just kind of curious when you're kind of – when you all are formulating your budget, does it create like a meaningful range of – or wider range of outcomes on sort of well costs and things like that?
Yeah, there's no doubt. My team is celebrating today the death of the Version 3.0+ and Version 3.0 taglines, because you can see we have 45 different completions. And even on 3.0+, we have 15 different versions of that.
And to answer your question, absolutely. Every one of those – and I think that this kind of illustrates the point. Every one of those has a different cost. Every one of those has a different result. And what we're trying to zero in on is return.
So as I look at the 2019 budget formulation, absolutely. You see various different completion recipes all throughout that plan, all with different cost. And again, we're focusing on capital efficiency and maximizing return. So yes, it does add to what the plans look like going forward and multiple different scenarios.
Great. And then, Tim, obviously just following up a little bit on your comments regarding certain steps on returning capital to shareholders will be forthcoming. And I'm just trying to – I guess from a thought process, in the past you've kind of talked about, really that's something that you wanted to think about more when you sort of reach the point of generating sort of excess cash flow from just operations.
But I'm curious if either the recent divestitures and sort of the upcoming divestitures, if kind of the combination and the proceeds from those and then just the massive cash balance, if I'm sort of thinking about it the right way, where you could potentially use that to sort of jump start some of those plans to kind of bridge the gap before you get to significant excess cash flow from just operations.
That's a great question, John. I think the way I look at it, we've got an arsenal of ways to deal with this question, both with regard to cash on hand prior to divestitures to divestitures to, as you stated, a free cash flow generative model in 2019. Those are all tremendous weapons to use at our benefit to try to solve for what's the optimal amount and the correct amount of return of capital to shareholders. And that's exactly what we'll be doing.
It is important I think from a fundamental standpoint that we actually get this company to where we are, in fact, generating free cash flow. I think that's 2019. That's the point at which we have always said we're going to be evaluating this in a more significant way. And that's our messaging today.
Very nice quarter. Thanks.
Thanks.
Next question will come from Arun Jayaram with JPMorgan.
Yeah, good morning. Tim, I wanted to get your thoughts on kind of the future of vertical integration at Pioneer. We've seen the company make some steps recently, including the U.S. Silica deal. And I know you're using a couple maybe third-party fleets.
But how do you think about vertical integration over the 10 year? And I was wondering if you also could just elaborate on your commentary about some initiatives that you have under place, maybe to improve the capital efficiency that you talked about in your prepared comments.
Yeah, sure, A.J. First of all, our objectives when we look at these initiatives are really twofold. And those are to make sure we're very competitive in the sense of future costs on wells and our whole D&C program. And there's various initiatives that are required in order for us to do so. One of which you've seen us accomplish at least to some extent already in the U.S. Silica transaction I mentioned.
Now the other though is to look at areas where we have capital going out the door that would have to be reconsidered or at least thought of differently perhaps in a world where we're trying to reduce capital spending. And so without going into a lot of detail, those are a couple of the initiatives we're trying to do. The 100% focus of course is improving our capital efficiency through time and making sure that we are in fact the low-cost producer.
Now when it comes to vertical integration, this is something companies like ours who have invested in vertical integration have to assess from time to time. As we look at an increasing rig count, going into the future of course, that's coupled with the increasing needs for frac fleets. We have to assess now whether we're going to invest in ourselves or whether we're going to use third-parties for that kind of a future investment. So those are the type of things we're looking at today.
Without any more detail, but we'll be announcing some initiatives in regard to various ways to cut costs and reduce capital spending over the next few weeks.
Great. And just my follow-up, Tim, lots of questions on your plans to return cash to shareholders. You do have quite a bit of cash on the balance sheet. Our question is, you do have some investments in midstream, thinking about your JV and your gas processing plus the water system. What are your thoughts about potentially on a longer term basis monetizing these midstream investing – investments and returning cash to shareholders through this avenue?
Yeah, I think if you look at gas prices, I mean we've been very pleased to have a seat at the table with our equity interest over multiple years with Targa, our partner. And that's allowed us to make sure we can keep ahead of what's going on in terms of gas production
The base – considering we're just one of the many producers which move gas through that system. In fact, we're about, in a given day, 35% to 40% of the throughput volume. So we're also speaking for the other 60% in terms of what growth rates look like to make sure that the capacity is in fact there. So that's been an important investment for us.
The water system is something that I would consider to be still under development. In fact, we are moving dirt and we are in the process of moving forward vis-a-vis our Midland water plant investment. Of course, that's going to take some time. We won't see first water from that until let's say the end of 2020 or so.
But at the time it comes on, it'll be 240,000 barrels a day of effluent water and will quickly move us to a point where we will not be utilizing any significant amount of freshwater. And that's substantial looking forward, in terms of making sure that we have the water capabilities to provide for that component of our capital needs to move our program forward.
That said, we'll evaluate these decisions as these processes move forward. Obviously today, water is really early from the standpoint we're just in the process of building new facilities.
Thanks a lot.
Yeah.
Next, we have Ryan Todd with Simmons Energy.
Great. Thanks. Great quarter, guys. Maybe a quick follow-up on the midstream as you're speaking of that. I know you don't have official guidance for capital in 2019. But as we think about 2019 and maybe 2020 or just over the next couple years, is there any meaningful change in the amount of capital expected to be spent on infrastructure, as we look forward over the next couple years?
Well I think if you look at midstream, for instance, the needs for gas processing will go up simply as a matter of the production of oil going up in the basin. And toward that end, I'm familiar with Targa's plans for 2019, which incorporate a couple new plants as well as another plant – or two to three plants, one might be in the early 2020 timeframe. And so there will be continuing capital required in that business, yes.
Okay. Thanks. And then I appreciate the commentary on a couple of additional rigs to be added in December. How should we think about the potential pace and cadence of rig additions in 2019? I know you don't have guidance. But in the past, you've kind of given us rule of thumbs at times in terms of pace of rig additions. And maybe any rough estimate on what POPs could look like in 2019 relative to 2018?
We're not going to be able to get into that level of detail, Ryan, until we establish it internally. We're still working on that.
I mean the fact is, with more rigs will come more POPs. You can think of it somewhat ratably. Now what's happened recently is our level of efficiency of drilling and completions has gone up so dramatically that we have to assess that in our planning and decide exactly how that impacts the need for rigs.
I mean certainly, in the models we've shown you in the past, we add a few rigs per year. I think what we'll try to do to deal with the 2019 program is to have a full year plan, such that we probably would make sure we incorporated any rigs in calendar year 2019 that would be effective only in 2020. In other words, rigs added in 2019 that would then affect 2020 production, we would put in the 2019 capital budget. So that will be one change you see us do.
Okay. Thanks. I appreciate it.
Next, we have Paul Sankey with Mizuho.
Hi. Good morning, everybody. Tim, you mentioned that – well, overall in the past, you've said that as you rise through your rainbow chart, as you call it, spending would go up with the oil price. It feels like with this result, as you mentioned, you have an inflection point, that we're reaching a terminal level of spending and rigs. I think that's what I heard in the previous answer as well.
Am I thinking about that the right way? Which is to say, if the oil price was to go higher from here, you wouldn't be adding rigs and spending, given the performance that you're seeing from the existing activities that you've got? And given that you're essentially on track with your long-term target?
Yeah, Paul, just to clarify, our long-term plan does envision us adding rigs through time, because it's necessary to offset what, in effect, becomes a larger base of declining wells through time.
But what we've said in the past, just to clarify, is that we're not going to accelerate activity in the face of higher prices. It doesn't make any sense, because usually associated with higher prices come higher costs. And so therefore, the last thing we want to do is accelerate into a declining margin scenario.
So I think what you'll do is see us stick to our knitting in terms of executing our plan. Price has become somewhat of an exogenous factor. And we'll be doing that through multiple years ahead. It's part of our 1 million [BOE] in 10 [years] plan.
Right. So the increased CapEx that you've seen this year has essentially not been related to the higher oil price?
Well, I mean, yeah. The higher oil price did have an effect on us, Paul, which we were very clear on last quarter, which has to do with we were in a different cost environment as a result of higher prices.
And so what has affected us more in 2018 is just reflective of the fact that prices were higher but not a difference in activity. We have added some rigs here, as I mentioned in my prepared commentary, at the end of December to prepare for, in essence, what amounts to 2019 production growth. And that's been well documented.
Understood. And then you're sort of walking away a little bit from just using the catch-all Version 3 description. But how is the performance of these multiple different techniques that you're using differing now? And if you could just expand on that, if you like, in terms of how we think about the future performance of these wells? Thank you.
I think I'll let Joey answer that, Paul.
Thank you.
Paul, I mean just to be clear, where we try these Version 3.0+ completions, they're in areas where we have a high confidence that they'll be successful, based on our extensive understanding of the 1,200 wells that we've put on to date.
But by no stretch of the imagination are we suggesting that Version 3.0+ completions work everywhere in every instance. And we don't execute our plan that way.
That's part of the reason why we're trying to go away from that. Because the nuances of the completions just make it so much more difficult to put them into buckets.
But in the areas where they do work, we're still seeing that they are yielding great, promising results. But again, we're just focused on putting the right completion to maximize our returns. And that's what we're focused on going forward.
It's very similar to the Stackberry and how we see that. It's we've proven the concept. It goes into our war chest. And then we're looking at putting together the best program we can each year that maximizes the returns.
And so the deployment of Version 3.0+ wells in conjunction with where we can do some Stackberry tests and all these things, the more we prove these things up, the more optionality we have, which allows us to leverage our infrastructure and our tank batteries and our water so that we can put together the most capitally efficient program we possibly can.
Okay. Thanks, guys.
Yeah.
Moving on, we have Charles Meade with Johnson Rice.
Morning, Tim, to you and your whole team there.
Hi, Charles.
I wanted to ask about the Stackberry test. And really the two that – I guess the one that's flowing back now and the one that'll soon be flowing back.
This first one was in western Martin. And looking at the rough map, it looks like you de-risked about a five-mile radius around that test. Can you talk about where the next two tests are going to be geographically? And whether we should – whether that's the right template to use, about kind of a five-mile radius of de-risking? Or at some point, will it be the case that you've done these in enough different kind of spots across your asset, your footprint there, that you can say, hey, we're de-risking a lot more of that.
Yeah, Charles, so the one that we put online this past month was in Midland County, kind of central Midland County. And then the one that we'll putting online here not too long from now is in Southern Martin County.
And to answer your question, I don't know that it's exact, but I would say general range of magnitude that, yes, we would expect that both these two tests would help us de-risk a similar amount of acreage as the one that we are currently describing, which is in Scharbauer Ranch.
Got it. That's helpful, Joey. Thank you. And then, Tim, perhaps this question might be best for you. You've got a lot of questions about things that – assets that you'd be looking to divest that are maybe outside of the core E&P operations.
But when I think back over your trajectory in the last few years, one of the things that's really differentiated Pioneer from other operators is that you guys have been out in front in identifying pinch points that may emerge and addressing those. And you could see this happen with water, with sand. You can make an argument that that's been the case as well with midstream and pressure pumping.
So while it makes sense that at some point, these investments mature and you want to move them on to different hands, are there other investments that you can talk about that you guys are considering that might not be on our radar now, but could be solving a problem that's going to materialize two years down the line for you?
Well, I think if you look at the things that are currently at issue, the ones that have been well documented are clear. And in particular, we're talking about what's happened with pipeline limitations from the Permian oil, in particular, and gas.
Gas of course gets mitigated somewhat as we get into the fourth quarter of next year, as the new pipeline to Agua Dulce comes on stream. Similarly on oil, you got the three new pipelines coming on to Corpus [Christi]. That gets solved.
Today, for example, basically frac space at Mont Belvieu is relatively tight. I think we're in pretty good shape on that. Then there will be some expansions early next year, so that gets solved.
I think longer term, one pinch point that I think the industry is going to have to deal with is making sure we're prepared with electric transmission to make sure that we're in good shape on electricity supply. Right now, I think that's really not a pinch point. But it's we have to keep vigilant on, mostly because it's not something we control. It's controlled by the PUC, the State of Texas, ERCOT, and our energy suppliers.
So that's one thing that doesn't get much air time, but nonetheless is something which we have to make sure we're focused on and continued, like our other businesses, to be planning long term.
That's helpful color. Thank you, Tim.
Yeah.
Next, we have Michael Hall with Heikkinen Energy Advisors.
Yeah, thanks. Good morning. Couple things to follow-up on. Maybe first on the marketing side, obviously we've got some movement in differentials. And that's expected to narrow out next year. But at the same time you guys are ramping barrels that are going to be moving to the coast.
Just curious if you'd be willing to provide some kind of broad strokes around what you think that marketing income might look like over the course of 2019? Or maybe directionally how it looks relative to the fourth quarter run rate? Any color you're willing to provide.
Yeah, Michael, I'd say that when you look at the forward curves is probably the easiest way to look at it. And look at where the Brent/WTI differential is, which is running right around $9 to $10 recently for 2019. So I think that gives you an indication of one piece of it.
Then if you look at the Midland differential relative to WTI, that varies next year from, call it, $5 down to about $2, so put it in that $3 range. So all-in, you're looking at $12. And our cost to do that is about $6 to – all-in from there. So that's kind of the differential. And you can kind of do the math then of what that would mean from an uplift that the company would receive over Midland pricing.
And what total amount of volume can you move next year do you think through all these contracts?
I think it starts at 200,000 [barrels] a day, and grows probably to 225,000 [barrels] or so by the end of the year.
Okay. That's helpful. And then on the NGL realization side, sorry if I missed any questions on this, I dropped for a minute. But you had very strong realizations, some of the best we've seen I think in the quarter. Is that sustainable relative to maybe a blended [Mont] Belvieu barrel or relative to WTI, however you want to think about it? Is that a kind of sustainable run rate you think? Or, yeah, any thoughts on that going forward?
No, I don't think it's sustainable, only because of what's happened with NGL prices since the end of the quarter. I mean if you look at what's happened in October, ethane prices, propane prices, and really the whole wide grade barrel has fallen. And so that was really a product of where commodity prices were during the third quarter that we benefited from and will still be getting market prices for our NGL barrels in Mont Belvieu for the fourth quarter. And so they'll reflect a lower forward curve.
Understood. Okay. That's all I had. Thanks.
Thanks, Michael.
Moving on, from TPH, we have Matt Portillo.
Good morning, all.
Hey, Matt.
Just one question for me. Tim, given your peer leading inventory depth and focused on a modest pace of development going forward, is there the potential at some point to look at a carve off of longer dated inventory? Potentially bring additional cash in the door and hopefully closing the gap on the deep, deep discount of the intrinsic value of your shares?
Yeah, great question, Matt. It's certainly something that we have as a top of mind issue. For the time being, I think our main objective is to evaluate our whole acreage position. Just like any acreage position in inventory, we have some areas that won't come with a premium in the sense of it's where it stacks up and when it's going to get drilled. So we have some acreage, some of our areas that just won't compete relative to some of our core of the core acreage.
And so we're actually doing an inventorying of all this acreage from an economic standpoint. And certainly going to begin the process by looking at that acreage which won't make the cut from an economic standpoint, using any kind of reasonable set of assumptions. And that's being done by our business development team as we speak. So you can expect that we'll have a goal set for 2019 to divest of certain assets that we think won't make the cut.
After that, everything else is under consideration, realizing we do have quite a long inventory in terms of really measured in decades. We've got to assess exactly what the next steps are in that regard.
Great. Thank you very much.
Next, from SunTrust, we have Neal Dingmann.
Morning. Tim, you mentioned this several times on the call. You guys obviously are outstanding on the financial side. My thought, and I've had some questions just with people asking about on the gas processing side. You obviously have a large facility there. I know I've talked to Neal about this in the past, about just your thoughts about what to do with that. I mean do you continue building that up? Do you monetize? How do you think about that facility, given sort of the success you've had with monetizations, other things like that in the past?
Yeah. As I mentioned in my earlier comments, Neal, I think that this has been quite an outstanding partnership between Pioneer and Targa, which has allowed us to keep ahead of gas processing requirements in the basin. And again not just ours, but others as well.
Plants will need to continue to be built. So we've got to make assessments as to whether we want to continue investing in those. And that's simply going to be a decision we make going forward. So I think certainly it's been a good set of investments for us. We have to assess that as we go forward.
Okay. And then, Tim, looking at slide 21. Obviously your FT is – there's nobody second to you all right now in this. The exports continue to climb.
How do you sort of mix – I know you mentioned now in that earlier slide, you're now relating that to Brent. But I guess my overall question is, will exports kind of continue to become a larger and larger piece of the business? Or how do you sort of view when you start sort of diversifying your takeaway?
Well, I think the fact is, with the Permian Basin growing as fast as it is, and that being all, relatively speaking, light sweet crude oil, there really is no alternative for the entire industry other than to export. We're going to satiate U.S. refining capacity demand for this type of oil, even though there are a couple of expansions under way, within a relatively short period of type based on that growth rate.
The industry has no choice but to export these volumes as a result. We just happen to be at the forefront of being prepared for this. And are taking advantage of it with, as Rich mentioned, at a point where we have 200,000 barrels a day being exported. That's a substantial amount of world oil demand being met by Pioneer's individual net volumes.
That said, the very – the big positive about this is we're seeing that this oil is in good demand in the world markets, in particular this light sweet brand of crude oil, works in a world where we're trying to reduce sulfur content in motor fuels and in maritime-related fuels. So it's right down the alley of some of the big refining centers.
Right now, because of what's going on in Asia, we're probably balanced more 60% to Europe, 40% to Asia. Prior to the issues with Chinese trade, we probably were more in the other side of the coin, 40%/60% in terms of 60% going to Asia. But we'll always find that there's opportunities in the world to take this oil. Furthermore, everyone would prefer to take U.S. oil supply versus countries for which there's a lot more political risk.
So we're seeing dramatic increases in demand. And that's where this oil is going. So we're at the forefront of that, really a major industry player now when it comes to the market for this type of oil.
Well, congrats, Tim, and props to your marketing team. They've done an exceptional job.
I will tell them you said that. Thanks.
And next, we have Derrick Whitfield with Stifel.
Good morning, all, and congrats on a great quarter and update.
Thanks, Derrick.
Perhaps for Joey. Referencing page 9 of your PowerPoint and the bottom right chart specifically, if you were to speak to one interval only, how many unique completion designs would you have across your position?
Oh, just to one interval only? I don't know that it would – well, it would be slightly different. But I would say just in the Wolfcamp B, and I'm just purely guessing here, you're still going to have 20-plus.
Sometimes whenever you go to the Lower Spraberry Shale and things – or intervals like that, we've discovered stage length isn't as much of a driver as it is in other areas. So there are some things that are distinct between intervals. But even across Wolfcamp B and Wolfcamp A, we have a wide variety of completion designs.
Got it. Very...
So I think the answer to the question is, there's really – it's not one-size-fits-all even by interval.
Very helpful. And then as my follow-up, perhaps for Tim. There's been a lot of discussion this quarter on efforts across the industry, to optimize spacing and minimize detrimental parent/child relationships.
You guys are clearly more conservative than most of your peers with spacing in the Wolfcamp. But you also have materially more inventory than your peers. If your position were 100,000 acres or less, would your development approach still be biased towards 750-foot spacing or wider in the Wolfcamp?
Derrick, this is the best question I've gotten in a long time, because it shows some insight into what's going on in the industry.
I wouldn't call us conservative. I would call us value optimizing. I would call us maximizing economics. What I mean by that, and I referred to this a little bit in my earlier commentary, if you don't have enough inventory, what you do is you basically drill the hell out of it. And you basically drill so many wells to – and the concept being, we're going to drill one more well to squeak out one more dollar of NPV, because that's the only alternative we have when we have limited acreage. And what that means is the last – the economics on the last well drilled are lousy.
We're taking the opposite view. We want the economics on every single well to be very, very strong. We stop when we start seeing degrading of economics on a per-well basis. We don't care about maximizing NPV per section, because you're going to drill uneconomic wells to make that happen, relative to our alternatives.
We're blessed with a vast inventory, which really helps us to stop when we start seeing diminishing returns in a section by drilling it too far downspace. So I don't think we're conservative. I think we're the beneficiary of our acreage position.
Thanks for the detail, Tim. Very helpful.
Yeah.
And next, we have Brian Singer with Goldman Sachs.
Thank you. Good morning. Going back to the well costs initiatives that you're taking can you talk about the magnitude that that could bring to reducing well costs and what U.S. Silica does? And when you think about – or when we should think about what some of the ones that are yet to be announced are, are they more contractual like U.S. Silica? Are they more process driven efficiencies? Or are they initiatives in which you'll actually spend some capital, but you'll get a return on that capital via lower well costs?
Well, let's just talk about the style of the U.S. Silica deal and what that means. To the extent that we are in effect with that contract delivering sand at about 50% of our alternative today, if you then consider, if that were to be applicable across a broader swath of our sand needs. And let's just say it were to be 100% of our sand needs, it would be saving us $400,000 to $500,000 per well. So I would call that dramatic in its own right.
Some of the other initiatives we're looking at are, on the one hand, intended to give us long-term cost advantages on D&C. And some of them are just related to cutting capital and putting us in a good contractual situation.
I'm going to leave it at that. But suffice it to say all these initiatives are based on improving our economics, improving our returns. And those will be substantial improvements.
Great. Thank you. And then you talked a little bit about just some of the building the pipeline risks. But I guess beyond that, as you prepare for 2019, what do you see as the key areas of potential risk around execution? And what are the mitigation efforts that you and the team are taking now?
I think we're well-situated for 2019, Brian. If you look at – of course we have a much more long-term planning approach. That's what happens when you establish long-term goals.
So every time a team comes in to talk to us about what they're trying to achieve to actually mitigate risks, it's about what are they doing to meet those long-term goals. So we have pipeline space locked up for FT, for both gas, oil, and NGLs that cover us, easily in the case of oil, through early 2021 or 2022. So we'll be working on pipeline deals, but they're not going to affect 2019.
If you look at our water supply today, we move about 500,000 barrels of water to our locations every day. That's because we have a large water system that allows us to do so. We're moving ahead on sand, as we discussed. And you'll probably see some more news on our ability to make sure we can increase those savings as well.
So it's across this whole broad range of initiatives that I can say 2019 is somewhat to the point where we could say, most of the issues, that if we had any, were already mitigated. Realizing we always have three years' worth of wells already scripted in advance.
So there may be issues, or maybe things that could occur. You can't ever rule out bad weather as an example. I mean we've seen that in the past. Right now, we're setting ranges for production that incorporate bad weather potential in our basin. And I think those won't affect us from the standpoint of ability to meet our targets.
But other than that, I feel very good about our execution. And our objective is to take the kind of momentum we've seen here in third quarter, take it into fourth quarter, and take it into 2019. I see no reason why we shouldn't be able to do that.
Great. Thank you very much.
All right. Ladies and gentlemen, that does conclude our question-and-answer session. I'd like to turn the floor back to President and CEO, Tim Dove.
Thank you, Greg. I appreciate everybody being on the call. I also want to make sure everybody has a great Thanksgiving. Thanksgiving is important for the country. It's important for all of our families, and I wish all of you a very happy Thanksgiving, and for that matter, holiday season following that.
And we'll be looking forward to giving you some updates in the interim as I said regarding some of these initiatives. And at the same time, we'll really be looking forward to our call in February, where we can outline our 2019 plan.
Thanks, everybody, for being on the call.
Ladies and gentlemen, that does conclude our conference for today. Thank you for joining us once again. You may now disconnect.