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Welcome to Pioneer Natural Resources Second Quarter Conference Call. Joining us today will be Scott Sheffield, President and Chief Executive Officer; Rich Dealy, Executive Vice President and Chief Financial Officer; Joey Hall, Executive Vice President of Permian Operations; 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 website, select Investors then select Earnings and Webcast. This call is being recorded. A replay of the call will be archived on the internet site through August 31, 2020.
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 the 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, Neal Shah. Please go ahead, sir.
Thank you, Shelby. 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’ll review and discuss our excellent second quarter results. He will also detail our framework for reinvestment that drives strong free cash flow generation and return of capital to shareholders. After Scott concludes his remarks, Joey will then review our strong operational performance and best-in-class oil production. Rich will then update you on our strong financial position and balance sheet strength. Scott will then return to discuss Pioneer’s focus on sustainable practices. After that, we will open up the call to your questions. Thank you.
So with that, I’ll turn it over to Scott.
Good morning. Thank you, Neal. I hope everyone’s doing well in this tough environment we’ve had over the last several months. I’m going to start off on Slide number 3. Despite the price collapse that we’ve had, especially for the second quarter, we’re delivering $165 million of free cash flow during that quarter. Look at for the entire year, and that’s based on a strip of about a week ago, and the strip has moved up. Brent’s already up to about $48.50 this morning. We were using a strip of about $46, but estimated 2020 free cash flow of about $600 million. Also on later slide, we’ll be increasing our guidance for 2020 for production, at the same time while CapEx guidance remains unchanged.
With our recent bond deal, we’re continuing to reduce our cost of capital and improve liquidity. Also we continue to be the best in the Permian Basin in regard to stats, in regard to flaring intensity less than 1% according to Rystad, which publishes the data from the – both the states of Texas and New Mexico in their data. And also continue to drive down costs pretty much at all levels, 16% decrease to our Permian lease operating expense, which Joey will talk more about later compared to the first quarter.
Going to Slide number 4, again, a very good quarter, despite the price collapse and the pandemic. We delivered 215,000 barrels of oil per day, total BOEs 375,000, again, free cash flow of $165 million during the quarter. It’s also amazing, we’re getting our horizontal lease operating expense down close to $2 per BOE, and again, maintaining our great balance sheet.
Going to Slide number 5, just talk to a little bit more detail about our cost structure. We’ve been focused on it for the last 18 months, continued to see lower and lower numbers. We’re driving our all-in cost of cash costs down toward that $4 range, LOE $2.17 for horizontal wells, G&A cash down to about $1.47, then interest continue to drive it down at $0.47, so a total of $4.11.
Going to Slide number 6, obviously, we’re improving our 2020 plan, maintaining our CapEx budget between $1.4 billion to $1.6 billion. We’re increasing our oil production guidance up to a midpoint of 208,000 from 203,000 range to 213,000. We don’t have it on here, but our fourth quarter exit rate, we’re increasing that. I think I said last quarter it was 190,000 to 195,000. We’re increasing it up to 200,000 barrels of oil per day for the fourth quarter. Again, total production up 356,000 to 371,000, the range.
Again, the rig count, the frac fleet count average from second quarter to fourth quarter remains the same. And again in regard to our deferrals even with the price increase, we have not brought back very little of our production that we mentioned was 7,000 barrels a day curtailed to the second quarter. This is primarily our high operating costs vertical wells, which we began a program over a year ago, but began to plug more and more of those wells over time. So I don’t expect the 6,000 very little of it to come back over time. Again, we’re seeing amazing capital efficiency gains at pretty much all levels, drilling completion facilities, lease operating expense, G&A and interest throughout the company.
Slide number 7, again, this is a new slide. This is our long-term thesis, but also I’ll talk about how it affects 2021. Again, creating significant value for shareholders. We’re targeting a 10% plus total return. That’s made up of a base dividend today, it’s over 2%, 2.2% at variable dividend moving forward. We expect to have a variable dividend and a policy put together for the year 2021 payable in 2022, and then an oil growth rate of 5% plus going forward. When you look at specifically at 2021, we do intend, as long as the oil strip at Brent is $45 or higher, we expect to begin plans for adding rigs and frac fleets going into 2021 to be able to grow 5% for the year 2021.
Long-term, we’re looking at 5% plus. We’re generating very, very strong returns, this is off the base as I had mentioned earlier in the previous slide of about 208 for the year for barrels of oil per day. We’ll be maintaining our great balance sheet at 0.75 or less, also we have a strong and growing base dividend long-term under that model. And as I said again, we’ll be adopting that variable dividend as long as the oil strip is $45 or higher for Brent and that will be payable in the year 2022. We’ll have the mechanics of that worked out by early 2021 and we’ll start discussing that at that point in time.
Slide number 8, we have an unmatched footprint. This is a new report by a sell-side group, showing the fact that we have three times our nearest competitor in regard to our inventory, over 10 billion barrels of oil equivalent, 680,000 acres and most of it contiguous, breakeven price less than $30 WTI, less than $2 Henry Hub. Let me now turn it over to Joey to talk about our operations.
Thanks, Scott. And good morning to everybody, I’m going to be starting off on Slide 9. As I did last quarter, I want to start off by congratulating and thanking the entire Pioneer team for another tremendous quarter, especially during the challenging times like we’re in now, 2019 was undoubtedly one of our best years in terms of safety, performance, efficiency, gains, and cost reductions. And the teams are committed to repeating that performance in 2020.
When you look at the graphs on the left, you can see the drilling and completions teams have already achieved 50% and 67% of their feet per day gains from 2019 respectively. Our facilities and development teams have also made remarkable progress in reducing our timing costs. When you look at these efficiency gains combined with service cost deflation and a consistent development strategy, we continue to drive down our well costs and drastically improve capital efficiency. As you can see on the right hand side, we have reduced our well cost by approximately $1.8 million or 20% in the first two quarters of 2020. We believe that approximately 60% of these cost reductions are sustainable.
Now moving on to Slide 10, starting on the left, once you normalize gross production for all peers on a 2-stream basis, Pioneer has the highest oil percentage. And then moving over to the right hand side, we also have the best 24 month cumulative oil production. So summing those two things together, Pioneer has the oiliest production mix and drills the most productive wells in the basin. These two facts combined with our low cost structure should lead to the best margins and highest returns compared to our Permian basin peers regardless of oil price. Once again, congrats to everyone for another great quarter, and I’ll turn it over to Rich.
Thanks Joey. I’m going to start on Slide 11 and good morning, everybody. This slide really highlights one of the many benefits of our acreage position, where we have a high working interest and high net revenue interest in all of our wells. And in simple-terms, we basically get to keep more of every barrel produced which means that we can deliver more efficient growth than others just because we have this high net revenue interest. And so what that boils down to us having to drill fewer wells, which leads to reduces our G&A and improves our margins. It also has the benefit of as drilling less wells and our inventory lasting longer. So a great benefit from our legacy acreage position.
Turning to Slide 12, looking at our operating cost structure that Scott talked about and as Joey alluded to, really congratulations to our field teams and supply chain teams, who have really done terrific job of driving down our lease operating costs by 27% over the last 18 months. It’s really been driven by optimization of runtimes on wells, optimizing the use of our facilities and revamping our chemical program. And they’ve coupled this with doing more of our maintenance internally versus using third-parties and then adding the supply chain savings on top of that, so overall, really a great outcome over the last 18 months.
Turning to Slide 13, this is a slide we’ve had in the past that just reiterates you the relative strength of our balance sheet relative to our peers when you look on chart at the bottom there. It also highlights many of our peers well, you’ll need to repair their balance sheets before they can return cash to shareholders and we’ll be in that position much sooner as Scott outlined.
So overall, we continue to believe that it’s important to have a pristine balance sheet with very low leverage ratios, which is why we view a net debt-to-EBITDA of less than 0.75, the target to be less than that on a long-term basis. So with that, I’m going to turn it back to Scott to talk about sustainability.
Thank you, Rich. On Slide number 14, again these are similar slides we’ve showed in the past quarters, Shale Oil and the study by Wood Mac, again it’s one of the lowest emission sources of, of all the various sources for oil, with oil sands and heavy oil, conventional onshore being some of the highest.
Going to Slide 15, this is a similar slide in the past. If you noticed we have dropped the names of the peer companies of this chart as we have in the – as we for the first time, but again the benefit of this is showing that there are reductions as Rystad goes into both New Mexico and Texas to look at the Permian basin. Companies are striving to reduce their flaring intensities, so almost everybody’s on board. I think this has helped in regard to see everybody in their stats. Also I’m still optimistic with two new gas pipelines coming on in 2021. And the reduced activity that the amount of gas is being flared will be reduced substantially in the Permian basin down to very, very low levels.
And then finally on Slide 16, again we have a great program in place. And I think with the fact that we have one of the best balance sheets in the industry also has probably the best rock in the industry in the U.S., which leads to great returns and allows us to be able to come out earlier than most companies to start growth of 5% in 2021, and also to be able to pay a strong base dividend and get into the variable dividend to deliver a 10-plus total program for our shareholders.
Let me go and stop there. We’ll open it up for questions.
Thank you. [Operator Instructions] We’ll take our first question from Doug Leggate with Bank of America.
Thank you. Good morning, everyone. And Scott, it’s great to see you articulate a very clear outlook for how will Pioneer represent in the future.
Thanks, Doug.
I got a couple of questions. One is actually around, if I may, Scott, sorry, I got a little bit of a delay on my phone. Obviously, you’ve said you’ll give us more detail on the mechanism, I guess. But to the extent that you can, can you walk us through how you think about the different methods of returning value to shareholders beyond growth, obviously, balance sheet, share buybacks, as well as a potential variable dividend?
Yes. I think I’ve stated in some of these past energy conferences. I think our industry, the history has shown over the last 10, 15 years that most companies have destroyed value by buying back stock at too higher prices. So, at this point in time, we do not anticipate using any of our free cash flow for stock buybacks. That’s why we’re going to the variable dividend model.
Most likely, the mechanics, only thing I know for certain, it will be paid in arrears because we have to go through the calculation of what our free cash flow is after the base dividend in 2021. So as we start the variable dividend, it’ll be paid in the following year after we make the calculation. So 2022 will be the year that we would pay a variable dividend and most likely it’ll be quarterly, but that’s about all at this point in time. The Board has not approved it at this point in time. We’re in discussions to discuss the policy over the next several quarters. We’ll give more detail in 2021 about the variable dividend structure.
So, again, we say 5% plus on production growth, some years it maybe 6%, some years it maybe 7%, but we don’t want to just tie to one number based on rig activity, DUC activity, frac fleet activity. We can’t hit 5% every year, so we want the flexibility, some years it maybe 7%, 8%, some years it maybe 4%, some years it maybe 5%, and so we’re just saying 5% plus on production growth over the next several years. But if we get into, obviously, a high oil price environment, say $60 to $70, we’re not going to change our production growth. That money will be paid out over and above the base. And we anticipate a small growing base dividend, but the variable dividend will be the structure that we’ll use to payout more and more of our free cash flow. Hope that helps.
Yes. It does. It’s tremendous. And I think you’re leading the industry in thinking about this, Scott, as you’ve done for some time. Look, I’d love to get into all the fantastic products and execution because those numbers are obviously terrific again. But I would like to ask you just a related question to growth. The company, since you came back, you reset the growth lower. Now you’ve come out with this thought-leading strategy, I think, but the company is built for 15% growth, I guess is the way I would phrase it. So what can you tell us about in terms of the structure of Pioneer going forward, the size of the company? Do you need to rightsize to adapt the organization to this newer strategy? And I’ll leave it there. Thanks.
Yes. As you know, Doug, we’ve already had a restructuring program last year and obviously coming out with a 5% plus production growth. We have – it’s under evaluation as to what size organization we need for a 5% plus production growth with more details to come over time.
Okay. I’ll leave it there. Thanks so much.
We’ll take our next question from Arun Jayaram with JPMorgan.
Yes. Good morning, Scott. Just maybe a follow-up to Doug’s question.
Hey, Arun.
I was wondering if you could – yes, I was just wondering if you could kind of walk through the decision to move to this long-term investment framework. And are there any analogs in the market today where you guys have studied, call it, a special dividend, a policy like this being implemented so that we could look for clues on how you plan to do this on a go-forward basis?
Yes. I mean, it starts with being in the industry for 40 years and seeing how volatile it is. So it starts with that. And you look at the past history of how much our industry has destroyed value whether growing too fast or buying stock at very high prices. So you got to look at the history of the industry and what should change.
And you look it up – and we have looked at over the last 12, 18 months at other S&P 500 companies, we’ve learned there was about 10 companies that have a variable dividend, not in our sector, that people are giving credit in other industries. So we’ve looked at those companies and how they pay a variable dividend, but we do have a cyclical commodity business. One of the issues in our business, as you know, it’s hard to predict what the commodity price is going to be. So we’re spending hundreds of billions – hundreds of billions of dollars every year, not knowing what our commodity is going to be over the next five years.
And so we don’t have much more detail than what I told Doug already on the mechanics of the variable dividend, but we see it being the main factor. And I tried to get away from the word special. I saw were Devon issued a special, and special is a onetime event. So when you look at a $50 oil strip, we will have a variable dividend every year for the next several years. So we know that we’re going to see some years at $60 Brent, we’re going to see some years at $40 Brent, but let’s say we average $50. The variable dividend I anticipated to be much greater than our base dividend, and so – under that model, and so I see it. So eventually I think we’ll get credit for it once you have two or three years of it and people believe in a certain commodity price, but we will start getting credit for that variable dividend. So I’ll stop there.
Great. That’s helpful, Scott. My follow-up question is just thinking about 2021. You mentioned in your prepared comments how you expect the fourth quarter oil rate to be a 200 KBD. Under your framework, it would appear that you’re targeting, call it, mid-single digits growth that would put you, call it, 215 plus in terms of oil next year thinking about the 208 base. I was wondering if you could help us think about spending next year. I think you mentioned that you’d be adding some rig and frac crew activity, but just wondering if you could help us think about spending relative to the $1.4 billion to $1.6 billion sustaining capital number that you’ve disclosed previously?
Yes. We put a range in there. We use that 70% of forecasted cash flow. Now that strip was running at $45, $46, and the Brent strips are already up to $48, $50. So if you look at us holding growth rates and we are starting our growth rate of 5% next year, so we are planning to add rigs and frac fleets to begin that growth rate above 208. So I would expect the Street to take our 208 midpoint, and basically add 5% to that for the year 2021. And so we’ll be adding rigs and frac fleet as we go into the year 2021.
To calculate our CapEx, you can use that 70%, but that was only $45 to $46 strips. So since the strip is continuing to move up, that 70% will drop, it’ll drop to maybe 65%, maybe 60%. It just – it all depends on where the strip is, so – to give you an idea where our CapEx will be, but we won’t give out our CapEx guidance until February.
Got it. So, mechanically, just thinking about 70% reinvestment at $45 Brent?
Yes, exactly.
Great. Okay. Thanks a lot, Scott.
And we’ll take our next question from John Freeman with Raymond James.
Good morning.
Hey, John.
I just had a follow-up question to that, Scott, where you just mentioned. So the 70% to 80% reinvestment rate is just based on the current strip. And it almost sounds like you view that as like the higher end of the reinvestment rate. And if we got into an oil environment, that’s $55, $60, something like that, you throttle it down, 70% to 80% just happens to be the range for the strip. Is that right, Scott?
Exactly. Exactly. Exactly. And that strip was a week ago. So I think all the news about the vaccines in Russia, India, and also Moderna, Oxford is that I think it’s got people excited with the market up and the oil strip has moved up significantly also just in the last week to 10 days since we made this run in this slide.
Great. And then a follow-up question, it was – kind of alludes to what Doug was asking about with kind of rightsizing the organization for kind of this more moderate long-term growth rate. You all highlighted on Slide 8, the massive inventory position that you all got and kind of moving to this kind of more moderate long-term growth target. I guess sort of how you all think about potential, again, in a more normalized commodity environment, not necessarily now, but in a more normalized commodity environment, how you all think about maybe potential acreage, divestments for acreage? You’re not going to get around to maybe for a really long time, but it would be a lot more valuable to maybe some of your peers in need of a top tier inventory and maybe sort of a way to kind of supplement or complement the variable dividends sort of policy.
Yes. John, I think the market is essentially dead right now. There is no cash deals being done by anybody. And so we’re just going to have to start waiting until we see some actual trades on deals. And so we have sold acreage in the past. We will sell acreage in the future, but we’re not going to give it away. So we are still doing large trades with all the various Midland Basin operators that will continue. But if a market ever opens up, there will be some divestments overtime on our tier two acreage and the fringes of our core area, but there is no market today. And the private equity market, as you know, is essentially dead.
All right. Well, thanks so much, Scott. I really appreciate it.
And we’ll take our next question from Brian Singer with Goldman Sachs.
Thank you. Good morning.
Good morning, Brian.
What do you view as the impact of falling costs on your breakeven oil price to meet your return thresholds? You mentioned the $45 Brent. You’ve got comfort increasing rig activity in the Permian to a 5% plus growth mode in early 2021. And so I just wondered if you can comment on the impact that that’s had. And then beyond that, the differences in leverage, what do you see as the unique drivers of the cost reduction to Pioneer versus what’s more broadly occurring elsewhere?
Yes. Rich?
Hey, Brian. On our breakeven, it’s really what we talked about last call as well as our breakeven still with the capital efficiencies that the team has done is in the, what I’ll call, the high-20s for Brent, low-30s for Brent on a pre-dividend basis for 2020. So that really hasn’t changed, it’s only gotten a little bit better because of the efforts of the team. So I don’t really see that having changed from where we were before.
And in terms of your second question on leverage, maybe you ask that one again.
It’s actually X leverage. What do you see as the drivers of the cost reductions that may be unique to Pioneer versus just a reflective of what’s going on in the rest of industry? And part of the reason that I ask is you guys are willing to increase your activity in the Permian beginning next year based on how you see your supply costs. And I wondered whether you have expectations for others to do that as well.
Yes. It’s similar to what all companies are doing. I don’t know that we’re unique other than we’ve got a strong focus internally across the board on all aspects of the cost structure. And so, as Scott outlined, whether it’s capital, whether it’s LOE, whether it’s G&A, whether it’s interest, we’re attacking all those relentlessly to make sure that we drive those costs down. And so it’s just to me, it’s really just a focus internally of how do we move each of those costs down and whether it’s supply chain, whether it’s efficiencies, whether it’s doing things differently, all those things are getting reviewed on a level for everybody internally at a microscopic level to make sure that we can drive those costs lower and lower over time.
And Brian, I’ll add, we’re starting earlier simply for one primary reason, we have a great balance sheet. So that’s the reason we’re starting earlier than most of our peers. I think it’s obvious that the peers are going to have to spend two or three years of deleveraging their company because the equity markets are closed. And so they’re going to have to use excess cash flow to delever to whatever their new debt targets are. We have maintained our great debt to EBITDA of 0.6 less than 0.75 and that’s the reason. The returns are good for everybody, but people just can’t return to any type of growth rate next year, except for maybe one or two or three companies in the U.S.
Great, thanks. And then when you think about the variable dividend model and returning more cash to shareholders and managing that growth to the 5% plus, how do you think about the importance of hedging? Should we expect that Pioneer would hedge to a greater degree than others, or not necessarily because the balance sheet, as you highlighted, does have a lot of flexibility within the framework of less than 0.75, and so there’s commodity price risk that an ability for the company to take on?
Yes, I think due to the fact that we’ve had three major downturns, 2009, 2014, 2015, and then this period, hedging has to be – it continue to be an important part of our planning policy. Even Pioneer was affected with our great balance sheet going into the second quarter. So if it wasn’t for Trump getting involved and calling on Putin and MBS, we could still have $20, $25 oil today. So even Pioneer would have been affected by $20, $25 oil for several months.
And so we just can’t depend on OPEC long-term. We’ve seen OPEC affect our business model for the entire industry worldwide, both in 2014, 2015, and this year. And so it’s an issue we’re going to have to deal with. I think everybody’s going to have to run a lower price case, and I think more and more companies are going to have to hedge. And – but we’re still – we got to look at cost as collars, still look at swaps and still look at three ways. So we’ll continue to have hedging as an important part.
Now it does move up about $1 per year over the next several years. So it’s still in contango. I would anticipate once it gets to a certain price that it’ll go into backwardation. I don’t know when that is, but hedging will still be important part of our policy, regardless of our balance sheet.
Great. Thank you.
And we’ll take our next question from Matt Portillo with TPH.
Good morning, all.
Hey, Matt.
Just a quick question around the common dividend, obviously, the variable is going to be a big component of growth going forward. Just curious how you think about the progression of the common dividend and where you might like to grow that over time? Or is the variable really going to take over as the primary driver of excess free cash flow?
Yes, obviously, today with over 2% base dividend, which is about the average, a little bit above the average of the S&P 500 is still a very strong base. We anticipate growing that slightly each year over the next several years. So I think it’s important to show that the base will continue to grow, but the primary driver will be the variable dividends. So I would anticipate the variable dividend significantly exceed the payout of the base dividend over time.
Great. And then as a follow-up question, you discussed the 5-plus percent growth for crude oil over time. Just curious in a higher crude price environment, as you talked about being able to recycle more and more free cash flow to shareholder returns, is there a limit to kind of the growth rate you would expect to see if we were in a $50 to $60 commodity price environment as you try to balance all the moving pieces?
No, I don’t see us – like I said, even if it gets to $70 or $80, I just don’t see us changing our policy. I mean, we’d have to have such an extreme shortage of crude oil in the world, which I just don’t see it in the next three to five years, but we could have a scenario where we’re so short of crude oil that the Permian Basin may be the only swing factor to actually add supply. That’s the only type scenario and I just don’t see it for the next several years, that scenario to happen for us to increase past a 5% plus growth rate. So we’re not going to change our policy over time.
And just to clarify on that, should we kind of think about it as a 5% to 7% growth rate? I think you mentioned 6% to 7%. Or is it really going to be a function of just the cash flow reinvestment at that 70% to 80% range?
No, it’s really a function of us, as I said, when we add rigs, when we add frac fleets, our DUC bank, all that plays into, I just don’t want to promise to exact 5%, so we’re saying 5% plus. So the rig, the addition of the rigs, the timing of those rigs, the timing of the frac fleets are going to govern – we want efficiency in the adding of those rigs and frac fleets, we don’t want to be stuck to one single number. So that’s why we’re saying 5% plus.
Thank you very much. I appreciate it.
We’ll take our next question from Charles Meade from Johnson Rice.
Good morning, Scott, to you and your whole team there. I’ll apologize in advance if I ask one more question about this 5% growth, but it’s one of the things that…
There are the variable dividends, right?
I won’t ask about that. But it’s one of the things that, maybe it’s a subtle distinction that you’re different from other peers, or maybe it’s not so subtle. But it’s one of the things that – it’s not a huge number certainly compared to what we’ve been dealing with in the past, but it is different. I wanted to ask though. So I think you – I really appreciate you already pointed out one of the big differentiators that puts a 5% growth on the map for you guys, where it’s not for most people is because of your balance sheet and that you don’t have to do any balance sheet repair.
But I’m wondering if you could elaborate a little bit on your thinking of some of the other conditions that maybe put that 5% growth into your plan. And I think part of it could be, you’ve already highlighted that the depth of your quality inventory, that’s a distinguishing factor for you versus other companies, but also maybe that there’s still a view you guys have internally that growth is part of the return you give to shareholders, and I think you’ve said as much. So can you tell us where that growth sits in your framework, your mental framework about how you deliver value?
Yes. As you know, the company was growing 20% to 25%. When I came back, we lowered it to about 15%. And I stated for a period of about 12 months that the whole point is to deliver a significant free cash flow. And actually the 15% growth rate actually delivers more free cash flow than a 5% growth rate. 5% growth rate delivers maybe for a couple years more free cash flow, but 15% growth rate delivers significantly more free cash flow under our model, and it still does today. The issue is, is that everybody else was growing 15% or higher, and we can’t – you can’t have the Permian and the U.S. Shell to add 1 million and 1.5 million barrels a day in a glutted market worldwide. It’s going to take a good two to three years to get the world in balance, reduce the inventories.
And so this is the best framework of picking a growth rate out. We think it’s still important to grow EBITDA. Most industries grow EBITDA, but it’s important to grow EBITDA. And so we’ve chosen that 5% production growth rate is something that we can do, be very efficient at it, and then provide all excess cash flow, basically to deliver inform of a base and a variable dividend. The reason we’re not just doing base is because too many companies have increased their base and then they get in trouble during a down cycle and then they have to cut their dividend as we have seen happen throughout the S&P 500, especially with the oil and gas industry and other industries. So that’s why the variable works in our cyclical nature. So I hope that helps.
That does help. And I appreciate you are connecting it back to the variable dividend. And then one other question, perhaps this is for Joey, you guys mentioned the improved capital efficiency, and we certainly see that from the outside looking in, but I was wondering if you could share your estimate of how much capital efficiency has improved or how much it should improve in the back half of the year versus what you thought coming into the year? And then, whether you all – you guys are leader on this – but the whole industry has become a lot more efficient than we thought possibly even 18 months to 24 months ago and just any opinion on you have on whether we’re at a kind of a peak of capital efficiency or if you can keep driving it better?
So good morning, Charles, and thanks for the question. If you remember last quarter, we actually had dotted lines on Slide 9 that indicated what we expected to achieve in 2020. And we had already exceeded those expectations in Q1, and it’s continued to go up in Q2. So we just continue to see efficiencies, continue to go forward. I still see some opportunity on the drilling front, whenever I look at drilling at our best wells, are still far better than our average wells. So we want to continue to get to where all of our wells are our best wells.
On the completions front, it’s a little bit of a mixed bag because we’re already in some cases pumping 90% of the time on location, which means we’re almost to a technical limit on how much faster we can pump a job. So the only opportunities there are to pump at a higher rate or go to something like a simul-frac. And those are things that we’re looking at, so there’s still opportunity there as well. But having said that, our completions teams continue to pull rabbits out of their hat and whenever you look at the cost savings that we’ve seen in 2019, so far 45% of those have come from the completions team. So it just continues to move-forward.
The other thing that we’re getting innovative in is contracting strategies, we don’t want to just go out and ask our contractors for one-time pricing relief. We want to build partnerships and have a long-term strategy to make that happen and we’ll continue to look at other technologies. So, frankly, if I would’ve – if you would’ve asked me this question two quarters ago, I wouldn’t have expected us to be where we are, but as you can see the trajectory keeps going up. So we’re going to just be relentless, it’s part of our DNA to focus on KPIs and continuous improvement, and technology management.
The one thing I would tell you is that, when you go back two quarters ago, our waterfall charts of cost savings were in big chunks. And now our waterfall charts are made up of a dozen items of things that we’re whittling away. So, it’s a never ending journey and we’re going to continue to focus on it and I still have hopes in the future that we’ll continue to drive our cost structure down.
Thanks for those comments, Joey.
And we’ll take our next question from Derek Whitfield with Stifel.
Thanks. Good morning all. Perhaps for Scott, in-light of your new investment framework and growth rates, how should we think about your non-D&C capital run rate over the next several years?
Non-D&C, I’ll let Rich to answer that question.
Yes, Derek we have it forecasted in the plan, but it’s continued to come down until it’s fairly nominal, when you think about the non-D&C and also DC&F, so things that are outside of that in years past its has been our water infrastructure. It has been the primary one with the Midland facility getting close to being done yet, we would expect that capital to continue to come down to a smaller level going forward.
Great. And for my follow-up…
We saw this year with $100 million. So it’s clearly less than a $100 million going-forward substantially less than that.
Thanks Rich. And for my follow-up, I’d like to shift over to your curtailments, are the remaining curtailed volumes, Joey, the price decision and for the volumes you’ve restored, were there any notable challenges in bringing those back online?
No challenges on the ones we brought back on so far and you are correct that, the really it’s a well-by-well positive cash flow, economic outlook that will cause those to come back on. And as Scott mentioned, some may never come back on, but as prices continue to move up, we will continue to bring some back on, we’ve already brought fair amount, some of the ones that we had in last quarter on, and we’ll continue to look at it well-by-well and add when it makes sense.
And Derek I’ll just add we’re keenly aware of the challenges associated with bringing back on vertical wells after they’ve been shutdown and our teams have done a great job of preparing those wells for shutdown and anticipation of bringing them back. So we don’t anticipate any challenges with that.
Thanks guys. Great update.
Thanks.
And we’ll take our next question from Michael Hall from Heikkinen Energy Advisors.
Thanks. Just a quick follow up a little bit some of the prior questions, but a little different angle. You guys put on a pretty tremendous number of wells in the quarter. I guess, I was just curious, is there anything different in the way you’re producing those wells or completing those wells, that we should keep in mind as we just think about I guess calibrating models going forward?
Yes. Michael, one thing having done this a couple of times, starting back in my days in the Eagleford there’s kind of the front-end of these developments for people who are focused on just getting these wells open and flowing them as high as they possibly can. And so everybody’s initially focused on well performance. And sometimes that comes at a cost, overbuilding infrastructure, putting in temporary facilities, maybe getting aggressive on artificial lift, but now that we’ve shifted our focus to capital efficiency and leveraging our existing facilities, which sometimes have limits on water production.
We might in some instances choke some of these wells back maybe take a little bit less of an aggressive bent towards artificial lift in some of our wells. Like I said, the lower commodity price has changed the calculus on artificial lift because that does come at a cost. So I think that’s the long answer, the short answer is, yes.
Hi, this is Neal. I can help you from a modeling perspective. If you think about the POP cadence for the remainder of the year, Q1 from our POP perspective at 85 would have been the highest of the year, really benefiting from the increased activity in the second half of 2019. POPs were of course, a lagging indicator on the capital that was spent the previous quarter. So you saw that 75, Q2 POPs really reflected the fact that we had a lot of pre-COVID activity before we started ramping down our activities.
We of course decreased our frac fleets as we stated in May down to one, so you’ll see Q3 POPs, materially stepped down vis-à -vis Q2. Now, as we are recurrently running seven rigs and three frac fleets, you’re going to see Q4 POPs rebound from the lower Q3 levels. So that should help hopefully calibrate some of your models,
I guess kind of guess question, what is the total TIL or POP count that we should be, I guess orienting towards for the full year now?
So we provided initial POP guidance when we had the initial budget because of COVID-19 and the disarray in terms of the quick reduction in activity, the strict POP count to production to well count really makes it more difficult So we kind of pulled that back, suffice it to say, we gave production guidance, we gave capital guidance. So that should really help. Hopefully if you take that and you take the waterfall, how I discussed how the cadence and POPs progressed throughout the year, that we will able to calibrate that in your models.
Okay. And I guess if I could kind of relate follow-up more on the – maybe on the completion side of things though you guys have continued to materially reduce well costs. I’m just curious, is there anything changing in the completion recipe, be it number of stages, propend loads, water rates, anything beyond just the efficiency gains that have been discussed that are driving the structural reduction in well costs.
Yes, we continue to tweak our completion recipes, but I wouldn’t say there’s been significant changes, the one area of focus that we’re focusing on to reduce costs, but making sure it doesn’t have a material impact on well performances is stage length. So if we can increase our stage length, then we can obviously reduce the number of stages we pump and get our costs down. So that’s the primary thing. We’re doing some tweaking on our Wolfcamp D Wells, but for the most part we’re relatively consistent on our completion recipes.
Okay. So completions and isolation, I guess we wouldn’t expect those to reduce, let’s say production per foot or productivity per foot, I mean it doesn’t sound like it’s anything material enough to change that.
That’s correct. We’re focused on getting the same production for a lower cost.
Okay. I appreciate it. Thanks guys.
We’ll take our next question from Paul Cheng with Scotiabank.
Thank you. Good morning. Scott, with the slower growth rate and look like you also assume the – based on the growth rate is going to be slower in the future. So how has that changed the way you approach the logistics side on the pipeline commitments going forward?
Change the pipeline and here the last part, the pipeline…
The pipeline commitment that how that will be changed?
I know those commitments are locked in at this point and they grow so, but we have plenty of access to barrels in the Midland market. So we’ll continue to evaluate it, but there’s no concern about being able to get the all – manage those pipeline commitments and to the extent that they’re higher than our production levels. So we’ll continue to monitor and watch it and manage it.
But at some point that your 5% growth you may reach in excess of your commitment and at that point, are you going to increase your commitment or do you feel more comfortable that you could be nick the short on the pipeline itself?
Yes, I don’t really see us adding any more commitment to this point. We have commitments that we will cover our equity production. So it really would be a case of we’ll stick with what we have today and that’ll be it. And if we have excess we can buy those barrels in the Midland market.
Okay. On the hedging program, then whether you gentlemen will think about to use a mechanical process, like every quarter, will be hedging, maybe, say, 12 to 18 months out and we’ve done this on the pricing condition to eliminate or take away the human emotional factor in the hedging program.
I would say, Paul is something we’re going to continue to monitor, and it will be something that we manage going through. So I don’t see it as a mechanical. I think we have a long-term history of hedging in advance of the production coming on, which Scott alluded to earlier and talked about that. We’ll continue to do that, but, I think we’ll look for times where we think it’s the ideal time to put those hedges on versus just doing it systematically.
I see. And final one for me, with the new growth model, I think Scott already mentioned that you guys will continue to do trade but I’m just curious that whether on a going-forward basis, from a divestment program, you become far more aggressive than you previously has been doing? And also whether it will impact in your spacing decision going forward?
No, Paul, I think the trades – I think we’re still doing trades with all the Midland basin operators. So we want to drill 10,000 or 11,000 or 12,000 foot lateral, as long as we can. So we’re trading 5,000 foot areas to add another 5,000 or 6,000 feet. So that will continue on. So I couldn’t tell that’s what you were alluding to, but we’ll continue to do….
Scott, sorry, I’m actually referring to that whether with the slower growth rate that you target, you clearly have a tremendous inventory backlog that one will ask you get – at the tail-end you may not lead it at all. So whether that to put the money forward that you become far more aggressive in selling assets in the future than you historically has been?
Yes, as I said earlier, Paul the market is dead right now. There is no cash deals, nobody has any cash to be able to buy inventory at decent prices, but I would expect the market to improve over the next two or three years and will continue to sell-off areas of what I call Tier 2 acreage as that market opens up. But right now the market is dead. There’s no private equity companies have no cash and companies are going to be de-leveraging for the next two to three years.
Sure. How about the spacing decision? Is that in any shape or form being intact?
No. If you remember our past slides, we started a wide spacing back in 2014. So we have not been down spacing at all over the last six years, like a lot of our peers that have less inventory.
Thank you.
We’ll take our next question from Bob Brackett with Bernstein Research.
Again, thank you for defining that investment thesis, both the level of detail and also the direction that it’s going in. I’m wondering if you’ve had conversations with the board yet around realigning management incentives to be aligned with this new strategy?
Yes. We’ve had lots of discussions in regard. In fact, one of the big changes that I’ve made this year personal on my long-term incentive plan, I think I’m the only CEO now it’s a 100% based on performance. We’ve also increased our management team, management committee’s performance level up from last year. And so we think stockholder return again is one of the key measures and I basically went to 100%. So if I’m in the bottom quartile of my peer group, I get paid nothing for instance. So it’s a 100% related. So those are some of the changes that we’re making.
And we’re looking at other changes over time in regard as you already know that we’re one of the few companies that has reduced salaries already this year, energy companies in regard to the pandemic. We also reduced our bonuses to zero. So again, we’re one of the few to take immediate action. I hope that helps. Bob.
That helps. A quick follow-up since no one’s asked it, we’re heading into an election cycle. Any thoughts of whether there’ll be any regulatory changes and how they might impact Pioneer going into 2021?
Yes. Right now it looks like the Biden is leading, it’s obvious. And unless something happens we’ll probably elect – this country could elect Biden and there’ll be some significant changes. I think most of that will be on federal lands. There’s discussion about banning on fracing. I don’t know what the end result will be. But as we have noted, we have zero lands on federal lands and so should be unaffected. But I would expect pipeline infrastructure will be significantly delayed, crossing state lines again all of our acreage is in Texas and we move our oil and our gas through the Gulf coast. So anticipate no issues there.
Thanks, Scott.
And we will take our last question from Paul Sankey with Sankey Research.
Thank you very much, everybody. And kudos for the very clear outline of the strategy, it’s greatly appreciated. Clearly you’ve got long-term visibility on your growth. Scott, I did wonder on the 5%, if that would imply 5% increases to the regular dividend and on the oil price variability side, you’ve then captured that with the variable dividends. My point would be, why wouldn’t you stop hedging because it adds the cost. You’ve got the business model that doesn’t need it. You’ve clearly showed that the balance sheet can handle a minus $37 quarter. And additionally, it makes your reporting very complex or at least appear complex. I just wondered if you would consider dumping that – secondly, on dumping hedging?
Secondly, on buybacks, there had been a disaster because people do them at the wrong time. Surely if the stock is undervalued and you believe that, and you know that essentially the buyback would be a good way to overall increase long-term dividends and generate value. Thanks.
Yes, Paul if we had zero debt and about $2 billion of cash on the balance sheet, I may consider dropping hedging, but due to the fact that we’ve had three down – I had three downturns in my first 30 years in the history of the business, and I’ve had three in the last 11 years. I anticipate we’ll have more over time. And so I don’t see a point in time. Maybe we can get there, but I’m not sure it’s the right strategy to put $2 billion of cash on the balance sheet and have zero debt.
So as I said earlier, if I won for the President call and putting in MBS, we still probably have $20, $25 oil today, just there still be a battle going on. And so we’re heavily dependent on OPEC. We’ve been dependent upon OPEC for a long time. Most of my career we can’t continue to have confidence in OPEC and that’s why I think it’s important to continue hedging. We do three ways primarily to give us upside. The thing we learned from this downturn is that three ways didn’t protect us. And so we’re continuing to look at different instruments that may be helpful but we’ll have to continue to hedge unless we move to a balance sheet with no debt and several billion on the balance sheet.
So that’s –your second question was more toward what…
Sorry to interrupt. There’s just a point in there about the 5% volume growth might imply a 5% still….
Oh, I see. No, we haven’t stated what our base dividend growth will be at this point in time, but we’ll evaluate it over time.
Yes. And then on the buyback, I mean, if the stocks fundamentally undervalued and you’re right about?
Yes. I mean, I wish – I mean, what’s sad is that we did not – we had one of the best balance sheets in the industry and we couldn’t even afford to buy our stock when it hit $55 in April, I guess it was April or May, but we had a bottom of $55. And so I knew in my heart that it was a great time to buy the stock, but we had the one of the best balance sheets in the business and we couldn’t afford to do it.
So, like I said again, does that mean I should go to a balance sheet of zero debt and 2 billion in cash to really ensure when volatile situations happen, like in 2009, 2014, maybe, but we’re just not moving there at this point in time. Anything else, Paul?
And we have no more questions…
Okay. Thank you. Again, we want to thank everyone. I hope everybody stays safe. We look forward to the next quarter and hopefully we can all loosen up and start seeing each other at some point in time. So I look forward to that day. Everybody take care and stay safe.
Thank you. This concludes today’s call. Thank you for your participation. You may now disconnect.