Pioneer Natural Resources Company - Q2 2019
August 7, 2019
Transcript
Speaker 0
Welcome to Pioneer Natural Resources Second Quarter Conference Call. Joining us today will be Scott Sheffield, President and Chief Executive Officer Rich Daley, Executive Vice President and Chief Financial Officer Joey Hall, Executive Vice President of Permian Operations and Neil 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 website, select Investors, then select Earnings and Webcasts. This call is being recorded. A replay of the call will be archived on the Internet site through September 1, 2019. The company's comments today will include forward looking statements made pursuant to the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause actual results in future periods to differ materially from the forward looking statements.
These risks and uncertainties are described in Pioneer's news release on Page 2 of the slide presentation and in Pioneer's public filings made with Securities and Exchange Commission. At this time, for opening remarks, I would like to turn the call over to Pioneer's Vice President, Investor Relations, Neil Shah. Please go ahead, sir.
Speaker 1
Thank you, Anna. Good morning, everyone, and thank you for joining us. Let me briefly review the agenda for today's call. Scott will be up first. He will discuss our strong second quarter results underpinned by solid execution and our reduced capital guidance for the full year.
After Scott concludes his remarks, Joey will review our strong horizontal well performance optimized for rate of return. Rich will then update you on the benefits of our downstream planning for both oil and gas. Scott will then return with a brief recap and commentary. After that, we will open up the call for your questions. So with that, I'll turn it over to Scott.
Speaker 2
Thank you, Neil. Good morning. On Slide number 3, on creating value, the first key point is we continue to buy back stock. And obviously, where the stock is today, we'll be continuing to aggressively buy back stock Q3 and averaging our price down. What's great is that we have the best balance sheet of the independents in the business to allow us to do this.
We lowered the top end of guidance of our capital by $150,000,000 with capital efficiency. We increased our dividend up to $1.76 per share with the yield about 1.5 percent and we moved to a quarterly distribution. We achieved our G and A savings much quicker than expected. 3rd quarter will be down to about $2.25 a BOE. On a cash basis, we'll be below $2 moving toward a target that we established for the company toward $2 in 20.20 and below $1.70 on a BOE basis.
We did achieve free cash flow when you add back in our restructuring charge for the 2nd quarter. Based on the strip of about a week ago, we're establishing significant free cash flow second half of twenty nineteen based on DC and F, on footnote 2, continuing to show great cash flow uplift for our vision about exporting crude oil several years ago to the Gulf Coast and exporting around the world. Dollars 81,000,000 second quarter, dollars 230,000,000 the first half. Going to slide number 4. Again, we're at the top end of guidance on production and with significant improved capital efficiency.
Next slide, slide number 5. Again, I mentioned that we're reducing our capital guidance at the top end by $150,000,000 Our drilling and completion teams are performing at very high levels around the clock. We've accelerated our West Texas sand utilization and reducing our infrastructure cost spending by about $50,000,000 lowering the top end of guidance by approximately 4.5%. Slide number 6, outlook is still great. Our $3,500,000,000 would have been increased over $3,600,000,000 without the restructuring charges.
Again, I mentioned congratulate our D and C teams for executing at a very high level of efficiency throughout the company. Slide number 7, on improving our cost structure. I've already given the highlights. Moving our targets down significantly, we're already in the top quartile of our peers. The goal is to stay there.
As I said, the goal long term goal is get below $2 per BOE. On a cash basis, we go below $1.70 and continue to drive it down over time. Slide number 8. Our priorities are aligned now with our shareholders, returning $825,000,000 already to the shareholders, including when you pro form a the dividend yield of 1.5% and buying back over 2% of our stock already with future buybacks to occur in the 3rd Q4. Increasing the dividend already, as I mentioned, to 1.5% yield and going to a quarterly distribution.
It's up 200% already from Q1 in 'seventeen. When you look at buying back our shares, pro form a dividend and growing mid teens, we're giving 20% back to the shareholders. On slide numbers 9, 10, 11 and 12, I'm going to go ahead and give some comments on the big picture items and hit a few highlights on those 4 slides on 9, 10, 11, 12. After returning and studying recent reports put out by Rystad, WoodMac, IHS, S and P Global and some sell side reports, I convinced Pioneer has the most productive wells and the highest returns in the Permian Basin, with the most contiguous acre position, has been drilling the widest spacing wells more than anybody else over the last 6 years. We do not have to down space.
Due to our continuous nature of our position in the Midland Basin. From these reports, the Delaware is being drilled aggressively by many more operators, rig count and Tier 1 acreage has been exhaustive at a very quick rate. Some of the reports have Delaware peaking in 2024, because of the aggressive drilling and down spacing because companies are essentially running out of inventory. The same reports are showing that the Midland Basin will not peak until the mid-two thousand and thirty's. I am lowering my expectations of the Permian reaching 1,000,000 barrels of oil per day growth annually as it did in 2018.
I'm still convinced the Permian will reach 8,000,000 barrels a day, but at much slower pace, with the Midland Basin as the only growing basin in the U. S. Past 2025. Going back to Slide number 9, 10, 11, 12, just to make a few key points and we'll turn it over to our next speaker. On Slide number 9, obviously, are just points to make.
As I mentioned already, I think they're mostly obvious of why the Midland Basin is the best place to be with our acre position in regard to well cost, oil quality, OpEx and commodity mix. Going to slide number 10, this is a slide from the sell side showing that we have the best returns in the business, not convinced by reading these other reports that we do have that. Also to help with those returns, Rich will talk more about the fact that we've aggressively hedged with the ramp in price several weeks ago with brand up into the mid-60s. We're aggressively hedging in 2019 with swaps and also for the second half and also in 2020, which will help our return on capital employed grow. Over the next several years, the goal is to get our ROCE up to the mid teens over the next 3 to 5 years in a $60 brand market or $53 $54 WTI market.
Slide 11, the key there is the fact that we already have taken positions of exporting almost all of our crude. We're getting the highest prices and the fact that WTI in Midland, 41 degree gravity is getting a premium price to Delaware crude. In slide number 12, again, we have an unmatched footprint, probably the highest net revenue interest among all the independents, low royalty. And it's interesting the fact that we saw a couple of things happen. 1 with us, we sold some non core assets this quarter for $20,000 per acre.
It's the first time we've seen a cash deal coming in from private equity over the last 2 years. We'll continue to do that as we see great opportunity to deliver on non core asset sales. In addition, we saw non core assets go for 31,500 per acre with the deal that Oxy announced recently. I'll now turn it over to Joey for Slide 13.
Speaker 3
Thanks, Scott. Good morning, everybody. I'm going to be picking up on Slide 13. And I know there's been a lot of discussion recently about well spacing and the resulting parent child effects. And as Scott just noted, Pioneer is in the enviable position of having approximately 680,000 mostly contiguous acres.
And it's our acreage position that allows us to prioritize returns and capital efficiency rather than artificially increasing our inventory through tight well spacing which as we know increases your exposure to the parent child impacts. It's this development strategy combined with advances in our completions methodology over time is what has allowed us to improve well productivity year over year as you can see there on the right hand side. Now I'm going to be moving on to Slide 14. Here we're illustrating an additional factor in our ability to sustainably deliver strong margins. Looking on the left hand side, you can see that based on gross production and normalizing on a 2 stream basis, Pioneer has consistently delivered the highest oil percentage in the basin since 2016.
And then on the right hand side, you can see that Pioneer also has the best 12 month cumulative oil production in the basin. These two facts combined with our development strategy discussed in the previous slide should lead to the best margins and the highest returns in the basin over time. Now moving on to Slide 15, my last slide. Here, we're highlighting another successful Wolfcamp D appraisal. This was a Wolfcamp D2 well pad in Western Glascott County.
And after 180 days, it is outperforming previous wells in the same area by 82%. We did pop 83 wells in Q2, and it's important to note that we've deferred some facilities projects into the back half of the year. Once again, and as Scott noted, a solid quarter of execution for the Permian team. Congrats to all. And now I'm going to turn it over to Rich.
Speaker 4
Thanks, Joey, and good morning. I'm going to start on Slide 16, where you can see that we had realized oil prices of $60 a barrel for the quarter. That did include a significant uplift related to the firm transportation, as Scott talked about, of moving our oil to the Gulf Coast where we get Brent related pricing. This increased our price by over $4 for oil for the quarter and as Scott mentioned provided about $81,000,000 of incremental cash flow or $230,000,000 year to date through June. Based on our forecasted prices for the Q3, we are expecting an uplift of about $25,000,000 to $75,000,000 in the Q3 from the ability to move our oil and export it on the Gulf Coast.
During the Q2, we moved about 90% of our oil, roughly 200 over 200,000 barrels a day to the Gulf Coast, of which 80% of it was exported, with roughly 60% of that going to Asia and 40% to Europe. Longer term, our firm transportation commitments increases to about 250,000 barrels by the end of 2020, which is consistent with our forecasted production growth. As I've discussed in prior quarters, we try to move all of our products to higher price markets. And during the Q2, we moved about 60% of our gas out west and priced it off a SoCal index. During the Q2, this provided about $25,000,000 of incremental cash flow and improved our gas price realizations relative to other Permian players.
Once Gulf Coast Express comes on in the Q4, we will move about 300,000,000 cubic feet a day to the Gulf Coast and price that on a ship channel price index. And at that point, virtually all of our gas will be sold outside of the Permian Basin. As Scott mentioned, before the pullback in commodity prices, we did aggressively hedge for 2019, 2020. So now we have for the remainder of 2019, 72,000 barrels a day of oil, hedged at Brent prices around $67.67,000 barrels a day of 2020 production hedged at roughly $64 per barrel, each of those with upside. Turning to Slide 17.
I think this slide highlights 2 key financial benefits that Pioneer has. First, it highlights the fact that we have the strongest balance sheet amongst our peers, and you can see that by measured against debt versus EBITDA basis. And then secondly, it highlights the quality of our wells and our cost structure as we have the highest EBITDA per BOE of our peers. This does not reflect the recent restructuring that we went through and the annualized $100,000,000 savings and so that will just further improve our margins. Both of these point to our industry leading financial position and our efforts to continue to improve margins and corporate returns.
So I'll stop there and I'll turn it back to Scott for a few closing comments.
Speaker 2
Thank you, Rich. On Slide 18, I think all these key points speak for themselves, but my primary goal was get the company to free cash flow as quickly as possible as I came back and I'm surprised how efficient and all 2,000 employees are working around the clock and got us there already 2nd quarter when I made the comment about getting free cash flow when you add back the restructuring charges for Q2. So that's what I'm most proud of. We're going to continue to deliver free cash flow and it's going to be a balance between growth, returning increasing dividends. As I mentioned earlier, in the past, the goal is to get up to the average of the S and P 500 as quickly as possible and then also continuing our share buyback program.
So again, I think all these key points speak for themselves, so I won't go over detail. But again, thanks. We'll turn it over now to a Q and A session.
Speaker 0
Thank And we'll now take our first question from Arun Jayaram from JPMorgan.
Speaker 5
Yes, good morning. This first question perhaps for Joey. But I was wondering, Joey, if you could maybe discuss the optimal project or well package size that you think is there to optimize returns and free cash flow generations from your asset base?
Speaker 3
So from an execution perspective, the 3 well pad is what has been our bread and butter through and through. But as time is going on now, we're increasing that to 4 6 wells and we're getting extremely good at that. But it's kind of hard to explain it as a package because sometimes we drill these larger projects with 1 rig and sometimes we do it with synced rigs. But I would say going forward, it's not going to be uncommon for us to see 4, 6, 8 and 10 well pads and probably the sweet spot, somewhere in the 6 well pad size.
Speaker 5
Great. And just my follow-up, Scott, in the press release, you guys highlighted how you believe that executing on a mid teens oil growth outlook is the best or optimal in terms of generating top tier returns and optimizing your free cash flow generation. My question is thinking about the next couple of years, you started the year running 24 rigs, you're down to 19. I think your guidance called for a rig count between 21 23 this year. We thought you needed to add 2 or 3 rigs kind of per annum to support that growth.
So just wondering how you're thinking about the next couple of years, particularly with Brent prices now moving towards the mid-50s?
Speaker 2
Yes. First of all, I just don't think the world is going to it could, but I don't think the world is going to be $55 for the next 3 years. That puts WTI down to about $48, dollars 49 net prices to people are 45. You're going to see a significant fallback in Permian growth. You'll probably move toward no growth for most people.
But on that basis, we got a great balance sheet. We have cash on the balance sheet and we can drill through the cycle if we choose. So we're sticking with our mid teens growth long term, adding 2 to 3 rigs per year. So I haven't we haven't changed our opinion at this point in time even if we go to the mid-50s.
Speaker 6
Great. Thanks a lot.
Speaker 0
We'll now take our next question from Doug Leggate with Bank of America.
Speaker 7
Thanks. Good morning. Scott, yourself and your offspring are the 2 only stocks green on the screen this morning. So congrats on the progress you've made since you got back. I got 2 questions, if I may.
First on the commentary in the press release about acreage sales on longer dated stuff that you might not get to in this slower rate of growth, I guess, versus what we had previously thought of Pioneer. How is that process evolving? Do you expect meaningful asset sales period? And if you could maybe just give us a broader update on how things are going with Targa and maybe your considerations around water infrastructure? Thanks.
Speaker 2
Yes. In regard to all three, both infrastructure items you mentioned, natural gas, midstream and water and also on DrillCo, we will update when we complete those three items. So I expect 2 of them will be done by the end of the year. And then water, as we mentioned in the past, We're evaluating it now and we'll make it the Board will make a decision in 2020. So all 3 are being evaluated and proceeding as expected.
In regard to acreage sales, we will continue as I've mentioned in the past over the last 2 years, there hasn't been much done, except for the Oxy transaction, which people have established acreage costs somewhere between $40,000 $55,000 per acre for that transaction by various sell side and external reports. We've seen this recent transaction for Ecopetrol, doing a deal with Oxy at $31,500 per acre In our treasure maps in the Midland Basins is where the experts, only 15% of that acreage was in core, 85% was non core. So it seems like a very, very high price for non core acreage. We would sell non core acreage all day long at $31,500 per acre. Hopefully, we'll get continued asset non core acreage for 20,000 per acre.
So we are excited about that transaction. And so far, the DrillCo process, as I mentioned earlier, if we decide to pursue with that by the end of the year, it's established around the same prices I've already mentioned, somewhere in that 20000 to 30000 breaker is what we would be selling a piece of the acreage for when you look at the returns. So hope that helps, Doug.
Speaker 7
It does, Scott. My follow-up is maybe for Rich. And it's kind of a philosophical question, I guess, because tripling or stepping up the dividend the way that you've done really starts to address an issue, I guess, that the whole industry has been challenged with, which is how to value the your sector, the EU in particular and obviously the general E and P space. Almost to the point of thinking along lines of a dividend discount model with the depth of acreage that you have in inventory and so on. So my question really is, in order to help the generalists do something like that, you need to have an idea what your thoughts are on future dividend strategy, payout ratios, trajectory for how that growth might follow your underlying capacity cash flow growth.
So I just wonder if you could share with us now that you've reset the dividend to remain competitive that has to have a growth rate with it. How do you think about that?
Speaker 4
Yes. I think as we've demonstrated and Scott talked about increasing it from $0.08 on an annualized basis over the last couple of years to $1.76 It's clearly a focus of the company as we move to a free cash flow generative model. As we think about it longer term, I think we want to get to a dividend level that's competitive with the S and P 500. We'd like to do that as soon as possible, but we got to be prudent about it where commodity prices are at. And as I said before, I mean, it's returning capital to shareholders is an important part of our value proposition and it's something that we'll continue to do over time.
Speaker 7
But is there like a payout target that you would consider like keeping it less than 10% of cash flow or something of that ilk?
Speaker 4
I think, Doug, over time, we'll have to evaluate that clearly. We want to be free cash flow positive and a chunk of that will be designated to go back into returning money to shareholders. I
Speaker 7
just had
Speaker 4
I just said the exact percentage today, I just can't tell you what the exact percentage will be, but it will be a fair amount of that free cash flow will be returned to shareholders.
Speaker 7
Sorry. Thanks, Rich. Appreciate the answers, guys.
Speaker 0
We'll now take a question from Jeanine Wai with Barclays.
Speaker 8
Hi, good morning everyone.
Speaker 2
Good morning.
Speaker 8
So in terms of the rig additions potentially in the back half of the year and trying to best position Pioneer operationally for 2020, Can you talk about what the primary considerations are for deciding on whether you do add those rigs later in the year and maybe how much lead time you need for planning purposes and how quickly you can actually pick up rigs?
Speaker 1
Jeanine, it's Neil. In terms of where our rig count average we put out in the beginning of the year in terms of where we budgeted, we have that average of 21 to 23 for the full year. We started the year for 24 rigs. We averaged roughly around that 21, 22 during Q2. We're exiting at 18 to 19.
So we expect and will remain well within our guidance. Q3 will roughly be, from a rig count perspective, flat with Q2. The Q4 activity will be based on our thoughts on the final 2020 plans, which we're still evaluating currently. But historically, as you've seen from last year, we it's all encompassed, as we know, as we discussed within the budget. So there would be no increase whatsoever to CapEx as we think about Q4 rig adds or activity adds in advance of 2020.
But again, we're still in the process of formulating our 2020 plans.
Speaker 3
And Janine, I'll just add that as far as advance notice, we have rigs that are available to us, and we just need 30 to 60 days advance notice to get those rigs back hot again and mobilized.
Speaker 8
Okay, great. And then I guess switching gears, your marketing strategy is a big differentiator for Pioneer and you transported 205,000 barrels a day to the Gulf Coast during 2Q. And I believe that amount of firm transport it ramps as you ramp your own production to over 250,000 barrels a day over the next couple of years. And there's been some debate in the industry on the status of just kind of new dock, new tank build out in Corpus Christi, the status of port dredging and all those other stuff. Do you think you can generally comment on your thoughts on this industry wide?
And then if you could provide any details on Pioneer's incremental dock and tank capacity that supports going from the 205 to 250 and whether there are any changes in your existing associated infrastructure over the next couple years too? So just trying to evaluate the risk reward of your
Speaker 2
marketing agreements.
Speaker 4
Sure, Jeanine. I think when you look at it and look at what's happening on the Gulf Coast, particularly in Corpus, there is a tremendous amount of export capacity being added. And so we don't see that as really a restrictive thing and we're glad to see that those are being added. We're glad to see the SPM projects that are hopefully get approved to take oil offshore and load bigger ships offshore. So I don't really see a bottleneck from that perspective related to what the growth of the U.
S. Crude market will be because most of that's got to get exported. What I would say in terms of Pioneer's contracts, when we built our profile going from when we started at 15,000 barrels a day up to the 250 by the end of 2020, we built in all the in those agreements that we would have storage capacity and dock space for all those barrels. And so even past 2020, as that $50,000,000 continues to grow, we have dock space and contracts to store it as well. So we've matched all those things together to make sure that we don't get stuck without being able to get it on the water.
Speaker 8
So I guess also the part of that is there's some debate on whether there's delays in new capacity with dock space and tanks and things. So can you just verify that everything you have is existing or are you relying on new projects?
Speaker 4
No, ours is all existing. So we're not relying on any new projects to meet our trajectory of production growth and moving those barrels offshore.
Speaker 8
Okay, great. Thank you for taking my questions.
Speaker 9
Sure.
Speaker 0
We'll now take our next question from John Freeman with Raymond James.
Speaker 9
Good morning, guys. Hey, John. Last quarter, you highlighted that one of the initiatives was on reducing field facilities capital spending partly due to higher utilization of existing facilities. So when I look at Slide 5 and about half of the reduction in the CapEx guidance was driven by the reduced gas processing and water infrastructure spending coming down by about $50,000,000 I'm trying to get a sense of how much of that is, I guess, you feel like a permanent reduction as opposed to some of that spending just being pushed to some outer years?
Speaker 4
Yes. I would say as it relates to timing on the well, I'm just taking order. On gas processing, it's really just timing. I mean, it's when the 2020 plant was going to get built. So it's just really timing there.
It will eventually get done. It's just because of the little slower growth. They don't need to build those plants quite as fast. On the water side, really that's really
Speaker 2
our subsystems. And so as we've reduced our growth profile
Speaker 4
a little bit and changed maximized the utilization of existing facilities. We're able to just push some of that capital out. And so it's going to get deferred. So those subsystems will get built in later years, but we don't need to build them in 2019.
Speaker 9
Got it.
Speaker 1
And then,
Speaker 4
yes, go ahead.
Speaker 1
John, I was going to say, that being said, tagging on Rich's commentary, we have talked about our water spending coming down next year as well. So it's not that you're going to see an increase in water spend for 2020 over 2019. While it is deferred, that water spend will still come down in 2020. Yes. The
Speaker 4
Midland water treatment facility, sorry, capital for 2020 is significantly less than what
Speaker 2
is in 2019.
Speaker 9
And I guess sort of along those same lines as my follow-up, the City of Midland, the wastewater treatment facility upgrade, it looks like that's a little ahead of schedule from what you all had planned last quarter where you said sort of early 2021 and now it's late 2020. Can you just remind us what the cost of that upgrade was?
Speaker 4
Yes. The total cost of that facility is roughly around $125,000,000 And I would say, John, there's really no change in timing. It's on schedule and on budget.
Speaker 9
Great. I appreciate it. Nice quarter, guys. Thanks, Doug.
Speaker 0
We'll now take a question from Brian Singer with Goldman Sachs.
Speaker 10
Great. Good morning. You mentioned, Scott, in your comments that you have the flexibility to spend through the cycle and the balance sheet is certainly at a very low leverage with minimal debt. Can you talk to how willing you are to use the balance sheet and where your leverage thresholds are either to drill through a down cycle or to buy back stock above and beyond internally generated free cash flow?
Speaker 2
Yes. I mean, obviously, we got to have various views on commodity prices, but I just think the long term goal is to have the flexibility and you can't have the flexibility without having a great balance sheet. So like I was asked earlier about $55 Brent, obviously at $55 Brent the next 3 years by I think Arun asked a question, we probably wouldn't change our plans. But we have the flexibility. If it drops too low, then we could reduce we have the flexibility to reduce the rig count.
We could stay with the rig count. But we got to combine that with achieving free cash flow. So our cost under those scenarios will come down significantly from the service companies as oil prices drop. So that's going to have a big so it's hard to answer the question if you do have a severe drop in commodities for several years. Generally, what's happened is that I just don't think the OPEC countries and the rest of world, lower oil prices will generate generally higher demand and things will pick up fairly quickly as we've seen through the various cycles.
So it's tough to really answer that long term, Brian. But the most important thing is that we have the flexibility to do any of the above that you mentioned.
Speaker 10
I guess what I was kind of hoping for maybe was, is there any upward leverage ceiling, by which you would say, what it's not necessarily worth drilling through? Or is there an upper leverage ceiling that you would be tolerant to buy back stock regardless of the commodity environment above and beyond what you're getting post dividend from free cash flow?
Speaker 4
Yes. I would say, Brian, that we wouldn't want our from a leverage metric, and I look at on a debt to EBITDA basis, we wouldn't want it to be above one times. We're just thinking in this business that we need to be below that level. So I think that would be what I would say the upper limit would be.
Speaker 10
Great. And then my follow-up is with regards to the Wolfcamp D results on Slide 15. Can you just add a little bit of color on what's different about the completions or the well performance of the locations chosen that drove the performance in here?
Speaker 3
Yes. So this is all three of the Wolfcamp Bs that we've reported on here recently are relatively far away from each other. I think in one instance about 10 miles and another instance about 18 miles and actually 50 miles away from our previous pad in the south area. So what we're doing is we're testing different areas. The completion recipes are relatively the same.
We've done some testing of different cluster spacing and different amount of clusters because the pressure is higher and our ability to create those fractures, it takes more energy. But for the most part, the completions have been relatively the same. But again, we're not really testing different methodologies. We're testing different areas. We've got 4 other future Wolfcamp D test planned and they're also in 2 of them are in similar areas to the previous 3 and the other ones are in new areas.
So again, we're mainly testing areas and appraising areas, not necessarily the completion technique, but we are making tweaks as we go.
Speaker 10
Great. Thank
Speaker 0
you. We'll now take our next question from David Deckelbaum with Cowen.
Speaker 6
Good morning, Scott and everyone. Thanks for taking the questions. Just wanted to ask, as you think about you talked about the rig plans going into next year's sensitivities around cash flows, I guess, just commodity prices rather. You think about the 21 to 23 rigs, should we still be thinking about that sort of flat split of 5 rigs in the South? I guess, what are you seeing there recently that is that going to compel you to increase allocation?
Or should that be kind of a steady state there?
Speaker 3
No, I think you could expect to see kind of a similar level of activity in the South as you currently see.
Speaker 6
Okay. I guess just I know part of the capital budget tweak down was realizing some of the or adopting some of the in basin sands a bit earlier than you had budgeted. I guess all else equal now, how do you think about your well cost trends going into the end of the year from where we are today? And do you still see some fat to take out going into 'twenty, I guess, on a percentage basis?
Speaker 3
I would say the big chunks. We've realized in the first half of the year that, namely being the ProPetro transaction and also the West Texas sand. The and some of those relate to other changes that we've made related to the type of chemicals and moving from gels to less gel and even to slickwater. So those changes for the most part have transpired. So I would say moving forward most of what we'll see are efficiency gains.
That's what we've seen both on the completions and on the drilling side. So I would say the big gainers have mostly happened in the first half and we'll just see efficiency gains in the second half of the year.
Speaker 6
Got it. And if I could just ask one more. Scott, high level, you talked about how in your view, you don't see any other basin in North America, I guess of size growing beyond 2025 other than Midland. Just given that view, does that how does that square with your thought process around pursuing some drill codes or selling acreage? Wouldn't that inherently kind of increase the scarcity value for your company over time?
And you already have a free cash projection out there that's achievable in the mid-50s. You're already growing in dividend. I guess, how are you balancing that as you think about just managing this business over the long term?
Speaker 2
Yes. As I've said before, David, the DrillCo acreage is focusing on acreage that is expiring over the next 5 years And that's where the main focus of it is. And so it's lower returns. It's still worth drilling today. And we've drilled a few wells on it and outside I mean, offset activities have shown that there are some other operators who are drilling in the area, but it doesn't meet our current hurdle rates above 50%.
And so that's the acreage that we're focused on, on DrillCo. So that's the main difference. But I think you're right, based on the scarcity, Midland Basin is the only basin growing. Past 2025, it will make Pioneer's properties worth twice as much money or 3 times as much money at some point in time over the next 5 to 6 years.
Speaker 6
Looking forward to seeing that. Thanks guys.
Speaker 0
We'll now take our next question from Charles Meade with Johnson Rice.
Speaker 11
Yes. Good morning, Scott, to you and the whole team there.
Speaker 2
I wanted to ask a question.
Speaker 11
You guys have already spoken quite a bit on the on your marketing arrangements. And I wanted to ask a question, perhaps for Rich. If you guys see there's already been some emerging differentiation between new grades coming out of the Permian. Do you guys see more differentiation? And I'm talking both in how you market and in the pricing that you receive going forward?
And looking way further down the road, if you guys have this 41 degree crude, my understanding is that's where we're going to be relatively short in the U. S. Compared to these lighter more condensate grades. And so long term, do you guys anticipate that actually that crude is maybe going to make it to the Gulf Coast but stay there?
Speaker 4
Whether it gets I mean, it's all going to get to the Gulf Coast for sure. And but I still think a big chunk of it's going to get exported. But clearly, the Midland grade, 40 one degree gravity grade is getting premium pricing to for the last 4 months or so. It's averaged about 1.50 dollars relative to the lighter crude coming out of the Delaware. And with the Delaware growth exceeding that of the Midland, as Scott talked about, I mean, there's going to be more of the lighter quality stuff on, which should make the value of our 41 degree barrel that much higher.
So I think you're going to continue to see that price move up. On the gas side, I think it's important to have takeaway out of the basin because I think any gas in the basin, there's not demand there. So it's got to get elsewhere and most of it's got to get to the Gulf Coast throughout California markets and mainly in the LNG markets. And so we're aggressively moving our gas via whether it's Gulf Coast Express or Whistler down to the Gulf Coast as we continue to grow and getting it locked into LNG facilities or exported to Mexico. So I think both those are important things.
Speaker 11
Got it. Thank you for that detail, Richard. And Scott, I've always enjoyed your macro comments and your willingness to offer your opinion on that. I have two quick questions for you. You mentioned Delaware peaking in 2020, 2024 and maybe in the mid-30s.
I was wondering what the Brent price assumption was for that? And then the second piece, as I'm watching the Permian, the volumes through 2019, I'm starting to the way it looks to me is that there's going to have to be more growth in the back half of the year than we've seen so far to reach some of these estimates for what Permian growth is in 2019 as a whole. And I'm wondering if you could offer your thoughts on Permian growth in the back half of twenty nineteen.
Speaker 2
Yes. I think most think tank groups are lowering their Permian growth from last year to about $600,000 to $700,000 for this year. And they're also lowering it for 2020 and going forward for all the reasons that I've said. So and that's due to the fact that people are drilling aggressively, they're down spacing. Now people are going to have less cash flow if we stay in the lower oil price environment.
People don't want to build debt in this environment. So there's a lot of reasons why I just don't think we're going to see the long term growth. So the majors are the only ones that are drilling aggressively. I don't see them slowing down. They've made some comments on their calls that they're having some issues.
But so right now, I just don't the growth is coming down for the reasons that I've mentioned. So I'll stop there.
Speaker 11
Got it. Thank you, Scott.
Speaker 0
We'll now take our next question from Bob Brackett with Bernstein Research.
Speaker 12
Question on the maturities of debt coming due in sort of 2020 2021. They're relatively modest relative to your enterprise value, but how do you prioritize either paying those down or refinancing them versus using the available funds for share buybacks?
Speaker 4
Yes. I think right now the current plan is we're really looking at a debt to EBITDA basis and where our leverage sits. But currently right now I'd say the 20 20, we're targeting to pay that off with cash on the balance sheet and still evaluate what to do with 2021.
Speaker 12
Great. And then a somewhat separate question. Scott, you mentioned earlier that you'd be happy to sell noncore acreage all day long at, say, 30 ks. Can you just sort of contrast what you mean by non core? Is it really high quality acreage that you wouldn't get to in a timely fashion?
Or is it the geologically sort of less core?
Speaker 2
Well, the piece that we sold for 20,000 breaker was an extreme North Martin County. If you remember, we did an asset sale about 3 years ago and that was on the Dawson Martin County line. It's in that similar area. It was isolated. So those are the type pieces that are non core.
It's a question whether or not you call the stuff we're looking in DrillCo area, I sort of call it lower tier core, But that's the acreage that we're focused on, on the DrillCo. And so we got an extensive acreage position, but so that's the difference between the 2. So I can't tell you exactly how much non core we have, but we do have some pieces that we can't trade or block it up. We're going to sell somewhere between that $200,000 and $30,000 per acre range. But fair
Speaker 12
to say it's more non Pioneer core versus non basin core?
Speaker 4
Exactly, exactly.
Speaker 7
Yes. Okay. Thanks.
Speaker 0
And that concludes today's question and answer session. I'd like to turn the conference back over to Mr. Sheffield at this time for any additional or closing remarks.
Speaker 2
Again, thank you for participating. Great questions, and we'll talk to everybody over the next 3 months and see you next quarter. Thank you. And
Speaker 0
once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.