Pioneer Natural Resources Company (NYSE: PXD) Q4 2019 Earnings Conference Call
February 20, 2020
Corporate participants:
Neal Shah — Vice President, Investor Relations
Scott Sheffield — President and Chief Executive Officer
Rich Dealy — Executive Vice President and Chief Financial Officer
Joey Hall — Executive Vice President of Permian Operations
Analysts:
Scott Gruber — Citi — Analyst
Doug Leggate — Bank of America Merrill Lynch — Analyst
Arun Jayaram — J.P. Morgan — Analyst
Jeanine Wai — Barclays — Analyst
Michael Hall — Heikkinen Energy Advisors — Analyst
John Freeman — Raymond James — Analyst
Joseph Allman — Baird — Analyst
Charles Meade — Johnson Rice — Analyst
Scott Hanold — RBC Capital Markets — Analyst
Brian Singer — Goldman Sachs — Analyst
David Deckelbaum — Cowen and Company — Analyst
Presentation:
Operator
Welcome to Pioneer Natural Resources Fourth 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 March 20, 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 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.
Neal Shah — Vice President, Investor Relations
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 with some introductory remarks.
He will then discuss our strong fourth-quarter and full-year 2019 results, driven by solid execution and continued efficiency gains from the teams. After Scott concludes his remarks, Joey will review our strong horizontal well performance optimized for rate of return, while delivering best-in-class oil production, as well as the drivers behind 2019 strong efficiency gains. Rich will then discuss the benefits of thoughtful, long-term planning and the impacts to our cash flow, as well as the benefits from our legacy acreage position. Scott will then return to discuss Pioneer’s focus on sustainable practices.
After that, we will open up the call for your questions. Thank you. So with that, I’ll turn it over to Scott.
Scott Sheffield — President and Chief Executive Officer
Thank you, Neal. Good morning and thank you for joining us. As you all know, 2019 was an excellent year for Pioneer. As we will outline, we expect 2020 to be even better.
When I returned to pioneer in February ’19, we set out a number of specific initiatives to return Pioneer to top performance. I’m happy to report all those objectives we had are now in place and now complete. While a difficult decision, we rightsized the organization to reflect a one-basin company, reducing our G&A to be top quartile. We organized and flattened our reporting structure, which had the intentional benefit of providing greater transparency and visibility across all levels, resulting in a company highly focused on strong execution in capital discipline.
During 2019, we assessed options to monetize long-dated non-core inventory that would have expired at little or no present value. We reevaluated our capital allocation framework to consider options to increase our cash flow profile and generate stronger returns. Today, we are pleased to announce that we have an agreement in place with Targa in our 2020 budget has no capital spending related to our interest in Targa’s Midland Basin gas processing system. Our noncore inventory monetization efforts resulted in a signed agreement for a Drillco in our Southern JV acreage, as well as the sale of approximately 8,000 net noncore acres that yielded approximately $130 million during 2019, putting value forward for our shareholders in a disciplined and thoughtful manner.
Lastly, our water system is still under evaluation, and I still expect an update in late 2020. At the field level, our facilities are now optimized to our current growth rate, enabling us to drive a more capital-efficient program. Also, we are making great progress, as you see in fourth quarter, in regard to reducing our lease operating expense cost. 2019 was an exciting year for Pioneer, a year of change, the year where we materially reduced our cost structure, increased our corporate returns, generated free cash, return to net new capital back to shareholders.
Thank you to all the employees of Pioneer for their hard work, strong will, and determination. The perseverance to achieve at the highest level that drives our company forward. Another milestone happened this week that I’ve been talking about over the last several months. EIA came out with a report early this week.
U.S. Shale is set to increase only 11,000 barrels per day of oil in February, 18,000 barrels a day in March. Its lowest growth in three years. All shale basins are in a decline now, except for the Permian.
Permian is expected to grow about 40,000 barrels of oil per day per month in the months of February and March, and I’ve been estimating roughly about 500,000 barrels a day growth in the Permian over the last several months. Flipping to our first slide, No. 3, and getting into the fourth quarter in 2020. I think the top thing, we generated $385 million of free cash flow in the fourth quarter.
When you look at just the second half of 2019, we generated over $600 million of free cash flow. A tremendous cost reduction we’ve seen, we’ll talk more about it later, and Joey will spend more time talking about it. But a 30% improvement in well cost in ’19 and 10% decrease in our Permian LOE. Again, what’s important, given capital back to the shareholders.
We’re increasing our dividend up to $2.20 per share to 185% increase compared to the full year of 2019. Also in addition, we’re continuing to buy back shares. We’re up to about 749 million. So we have led about 1.25 billion on our authorization. Also very important in regard to — we’re the best in-basin now. We were in second place. We have moved up to first place. Less than 1% of our produced gas flared.
And then probably one of the most important items besides free cash flow, where we’re focused is the increased return on capital employed, 11% we delivered in 2019, that’s up from 9% in ’18 and 4% in ’17. What’s amazing about that, that with a 12% drop in oil price of WTI to achieve that ROCE of 11% in 2019. Going to Slide No. 4, obviously, we had a very successful fourth quarter.
At the high end of production on oil above total production, 363,000 barrels of oil per day. Again, free cash flow of $384 million, also keeping a very, very strong balance sheet. And you can see the summary for 2019. Again, the key point oil production, the top end of guidance, total production above the top end of guidance.
Going to Slide No. 5. Again, a really key focus on reducing well cost, a 30% reduction, you can see on estimates going from about $12.5 million down to about $8.5 million per well. That includes full D, C & F costs. We’ll talk about each of these items when we turn it over to Joey later. Slide No. 6. In regard to 2020 outlook, again, it’s what we’ve been talking to the street about 235 to 245 oil.
Total production 383,000 to 403,000 barrels oil per day. All products are sold in premium markets, obviously, including natural gas. Capital budget of about $3 billion to $3.3 billion. Again, cash flow based on the current strip, and we’re almost back to the price that we were using, brings back to about 59 for the rest of the year. This has run on a $60 Brent case or a $55 WTI case but cash flow of about $3.9 billion. Rich will talk strong hedges in place. And even with WTI going down to $50, WTI, we only see a drop of about $200 of free cash flow. Balance sheet expected to improve down to 0.4 between now and end of the year.
And if you look at the midpoint of oil, we are growing about 14% oil for the entire year. Slide No. 7. In regard to operational plan, again, we’ve been saying over the last 12 months, we’ll be adding roughly two to three rigs per year. This gives you the rig count, the number of POPs. It’s about 360, about the midpoint, same well mix as we saw in regard to 2019. We have a couple two or three new slides that we worked on. These are things we’ve been saying to investors in regard to wide mid-teens growth.
It’s a combination of execution, free cash flow, net asset value, return on capital employed. And each of these items are affected depending on what growth rate is the key point I’ve been making. The growth rate is the output, what you’re trying to accomplish all four of these. I think the key driver is free cash flow and ROCE in regard to how we’re running the company today, and we have a great inventory that we can deliver this program for a long time to come.
Slide No. 9 just shows you the benefit, especially when you have $600 million to $900 million of free cash flow in a $55 WTI price environment for 2020. Maintenance capital is about $2.1 billion now. And with our base dividend and dividend increase be part of the growth capital, you can see even at $40 WTI that we’re able to pay most of this and part of the growth capital, even at a very, very low price, so continuing to drive down our breakeven price.
Slide No. 10. Again, another way to talk about what we’ve been discussing in regard to where does free cash flow go. Obviously, we have stated to get our base dividend up to about the average of the S&P 500. We’re getting close. Obviously, with our recent increase, long term, we’ll continue to look at further increases in the base. In regard to share repurchases, we’ll continue to do that opportunistically. We’re still going to have a great balance sheet, as you can see, we’ll be driving our debt-to-EBITDA down to about 0.4 in a $60 Brent or a $55 WTI price for the entire year.
And then we’ve been exploring with a lot of our shareholder base over the last several months, and we’ll continue as we go out and discuss weaker orders, the variable dividend. I think the reason that’s been introduced because everybody knows we have fluctuating commodity prices. And secondly, we do not want to get the base up so high that you run into any type of situation where you even consider cutting a base. And so the best option is to create a variable dividend and pay that out to the shareholders.
Slide No. 11, again, just reemphasizing the fact free cash flow going back to the shareholders. After buying back over about 750 million of stock in addition to our dividend going forward, it’s about 360 million. So we got about 1.1 billion. When you combine the two together that we return to shareholders, again, a 185% increase from our dividend we paid in 2019. Again, emphasizing ROCE up to 11%, and that’s with a 12% decrease in oil price, as you can see from $65 to $57. Also, you can see this is all prior to the fact that we focused on the cost side of the business. On to Slide No.
13, top-tier returns, driven by low acreage cost basis. As you can see, a key point here, besides the fact that we went up from 9% to 11% in ROCE, when you look at using Credit Suisse information that our peer average actually decreased down from 8% in 2018 to about a 6% average. So we’re gaining on Tier 1 significantly in 2019 and starting to move above the pack from Tier 2 to Tier 12. And a lot of it has to do with the fact of our cost structure, and secondly, the fact that we essentially have very little investment in most of our 680,000 acres.
Slide No. 14, I think you’ve seen this already. I think the only other key point here is that there’s a couple of key points here to emphasize the fact that starting to see certain large integrated and also some large Permian companies move to a greater mix in the Midland Basin when you look at the amount of acreage that they have. And so we’re seeing that.
And I think that’s obvious why. When you look at the benefits of the Midland Basin of Delaware, and another key point we’ll emphasize too when we get into the flaring slides, the ESG slides, is at the Midland Basin, obviously, when you look at the amount of learning that’s going on. The biggest color is in the Delaware Basin. It’s primarily due to the fact that the Midland Basin’s been there a long period of time. And that’s a lot more existing infrastructure. Again, Slide No. 15, we probably have the best footprint and work in a world-class asset. This shows the two acreage noncore deals that we made in 2019 for $129 million.
In addition, over 10 billion barrels of resource base with 680,000 acres. In my first opening statement, we did make a comment about the fact that we have signed up a recent DrillCo to drill about nine wells, and that will start shortly in regard to taking acreage that will eventually expire over time in our Southern JV acreage. Slide No. 16.
Again, this slide has been around — it just shows you the percent of acreage that’s been developed, coming out of Wells Fargo, pioneer leased a pack significantly of everybody in the Permian Basin, years of inventory breakeven in less than $50 WTI. We’re way out to the right, and we’ve developed very little of it is the key point with this slide. I’m now going to turn it over to Joey. Thank you, Scott. Good morning, everybody. I’m going to be picking up on Slide 17. Continuing a theme from the last two quarters and starting on the left-hand side of the slide, you can see that when you normalize gross production for all peers on a two-stream basis, Pioneer has the highest oil percentage. And then moving over to the right, we also have the best 24-month cumulative oil production, so simply stated, Pioneer has the oiliest production mix and drills the most productive wells in the basin. These two facts, of course, combined, should lead to the best margins and the highest returns in the basin over time. Now moving on to Slide 18. As Scott already mentioned, our execution teams had a tremendous year, most notably by reducing our well cost by 30%. As you can see on the left, a large portion of these savings were driven by significant efficiency gains on our feet per day in both drilling and completions have improved over 30% since 2017, with most of these gains coming in 2019. And although, not highlighted here, and as Scott has mentioned, our operations team also realized significant cost reductions and facility construction and we’ve also achieved significant reductions in LOE. And additionally, as you can see on the right, our field development team continues to plan and deliver best in-basin oil wells. And of course, building up my previous slide, lower well costs, combined with increased productivity leads to improved capital efficiency and top-tier returns. I’d like to offer my congratulations to the entire Pioneer organization on a great year. Thank you to our geoscientists, analysts, engineers, supply chain management team, and especially, those executing safely out in the field every day for a tremendous year. And I’ll now turn it over to Rich.
Rich Dealy — Executive Vice President and Chief Financial Officer
Thanks, Joey, and good morning. I’m going to start on Slide 19. And this slide, really, is to highlight the attributes of Pioneer’s assets and the strategy that we employ to improve margins. Generating strong margins, as you know, is key to improving corporate returns, maintaining a strong balance sheet and returning capital to shareholders.
You can see from the graph on the right that we generate share-leading EBITDA per BOE margins. This incremental margin relative to our peers is a function of the higher percentage of oil that we produce in our wells that Joe just talked about, our high net revenue interest in our wells that I will talk more about in a minute, and maximizing the price that we received from the products that we sell by moving into higher-priced markets, so also driven by protecting our cash flow with derivatives and, as Scott talked about, our strong focus on reducing our cost structure. If you look at the graph, it is just for the third quarter, just to give you an updated view, recalculate that on our fourth-quarter basis, our EBITDA per BOE increased above $31 per BOE, reflecting the benefit of higher commodity prices during the fourth quarter and the company’s continued cost-reduction efforts. Turning to Slide 20, this slide really highlights the benefits of our legacy acreage position, where we have low bases and high net revenue interest.
You can see on the chart on the left, the benefit of having a high net revenue interest. The chart illustrates how much incremental drilling activity that our peers must execute in order to accomplish the same level of growth is pioneer. In addition to more efficient growth, our high net revenue interest across our acreage also provides for better returns and higher margins, as Joe discussed. And then when you think about it from a drilling inventory perspective, chart also illustrates how much faster our peers have to drill through their inventory to accomplish the same level of growth is pioneer.
Turning to Slide 21, this really highlights the focus of our improving cash flow margins by moving our products to higher-priced markets and using derivatives to protect cash flow. In particular, during the fourth quarter, we significantly improved our gas price realizations by selling our gas outside of the Permian Basin. With Gulf Coast Express coming online, we transport nearly all of our gas to the West Coast or the Gulf Coast, selling it there versus selling it in the Permian Basin. This resulted in gas price realizations being $2.21 per Mcf versus if we’d sold it in Permian being based on Waha index of $1.11.
So a significant uplift. On the oil side, we transported nearly all of our 220,000 barrels a day of production to the Gulf Coast, and 95% of it was exported during the quarter. So you can also see on the right side of the page that we have a strong derivative position for 2020 with 67% of our first-quarter oil production and 54% of our full-year oil production protected with derivatives at $62 Brent prices with upside to the high 60s. As a result of this strong derivative position, our cash flow variability between 55 and 50, as Scott talked about, is only about $200 million.
So you can see that we’re well protected in 2020 from oil price volatility. So I’ll stop there and turn it back over to Scott for some discussion on environmental progress.
Scott Sheffield — President and Chief Executive Officer
Thanks, Rich. On Slide 22, delivering low-emission barrels. You can see our shale oil business is close to leading the pack in regard to lessen low density, including methane. This is coming out of a Woodmac report with McKinsey report that was published recently.
When you look at Slide No. 23, we’re the lowest of our peers in emissions intensity. We’re pioneers on both rehouse gas intensity and also methane intensity. This is a primarily due to the fact that we have some of the best LDAR program lead detection and reporting, low-level flyovers that we’re using one of the few companies as doing low-level flyovers within technology, our VRU captures, vapor recovery units.
We’re one of the first to require every gas line has to be — the gas line has to be connected on essentially all new horizontal wells. And one of the major changes we’re making in our ESG in regard to compensation, we’re increasing that piece from 10% to 15% going forward in 2020. Looking at Slide 24. In regard to the flaring, obviously, has been in several newspapers, including the New York Times recently, Pioneer, happy to report, we’re now No.1 in regard to — we have been No. 2. When you look at some of the data in 2018 and looking at the data in ’19, Pioneer was down less than 1%. At No.1, we recently probably had the largest flaring, the first and the largest flaring conference in Austin, Texas that was put on by Colombia and UT Energy Institute. I think coming out of that conference, we have agreed, and we like to get all producers committed to this. We’re committed to better reporting to all agencies, both in the state of Texas and New Mexico. We’re committed to sharing best practices among all producers.
And thirdly, a couple of interesting ideas came out. We think it’s important to set a percent target. Pioneer would like to be able to continue to produce below 2%. If you look, there’s only really six companies that are below 2%.
I think every CEO has set a target of 2% or less. It will help solve the problem. And the another interesting idea came out of the conference, and in fact, it’s back to the shareholders, shareholders and public companies, shareholders and private equity companies, shareholders in regard to bonds that are being done is that if all could help and also require companies to be 2% or less, they’re not 2% or less within a certain period of time, especially when the two new pipelines come on in the first half of 2021 that you would end up either not doing business or sell whatever you have in regard to that company, that would also help. So those are some of the interesting ideas coming out of that conference.
I think it’s important to remove that black eye on the Permian Basin going forward. Final Slide No. 25. Again, the company tremendous turnaround from 2018, focused on returns, capital disciplines in place, return of capital is in place already, probably the best balance sheet of being independent in the U.S., and we have probably the best inventory of the new company going forward.
So I’m going to stop there, and we’ll open it up for Q&A.
Questions and Answers:
Operator
[Operator instructions] We’ll now take a question from Scott Gruber with Citi.
Scott Gruber — Citi — Analyst
Good morning. Can you hear me?
Scott Sheffield — President and Chief Executive Officer
Yes, Scott.
Scott Gruber — Citi — Analyst
So, you’re investigating the possibility of a variable dividend. Scott, how do you think about where the prudent take of the base dividend? You say in the deck that you’ll continue to increase it. How do you think about where to take it? Do you think about percentage of cash flow, percentage of cash flow above maintenance CapEx? Some framework on that front would be great.
Scott Sheffield — President and Chief Executive Officer
Yes. We haven’t established a percent. I mean, we’re looking at other and studying other industries that have had variable dividends. We’ve had several companies and other industries that have had successful variable dividends. We’ve got a lot of those comments from and talking to a lot of our shareholders over the last 12 months. We’ll be going out again and visiting with our shareholders over the next two to three months in March and April, with deployment and talking to them and go into a couple of the conferences and still trying to establish it. But at the end of the day, we already have a great balance sheet, and we’re going to establish a base, and that base is going to be, say, eventually close to the S&P 500 around it and with slight increases going forward on that base. But then when you look at the amount of free cash flow the company has, and we’ve mentioned before, I did in the Barclays conference, that we have over $5 billion of free cash flow over the next five years.
You still have sufficient amount of free cash flow, what do you do with it? And like I said, we don’t want to — and most of our shareholders that we’ve discussed do not want an E&P company getting your base up so high, and so it leads toward a variable dividend. And so we’ll have to come up with the mechanics as we develop our first-year significant free cash flow over and above our base dividend and any stock buybacks. That’s what’s left and have to come up with a plan. And we’ll be busy with everybody as we speak with you over the next several weeks.
Rich Dealy — Executive Vice President and Chief Financial Officer
Yes. And Scott, just one other thing to add to that. We believe it’s important to have a stable and growing dividend, so kind of underpinning on the base. But we also think about that growth needs to be consistent over time with the S&P 500 or slightly better. And that’s where we want to, over time, lead the base dividend.
Scott Gruber — Citi — Analyst
Great. And unrelated follow-up. If I look at Slide 5 in the deck, you guys did a great progress on well price during 2019. You showed continued efficiency gains into ’20. But when I divide the midpoint of your core CapEx, about 315 of your POP guys of around 360, I come to an average well cost that’s around the 2019 average. Why isn’t that simple math showing a greater reduction? Is there something that’s impacting the year-on-year comparison?
Neal Shah — Vice President, Investor Relations
Hi, Scott, it’s Neal. If you look at what we did in 2019 in the capital program, the 2020 capital guidance also includes any potential rig adds toward year-end that we require for 2021, again, similar to what we did last year. So that’s embedded in there as well. Also, that range encompasses somewhat and correlates to the range and POPs, so there’s a correlation between the two. Also, I’d say if you look at the strong efficiency gains that we experienced throughout 2019 that led us to over accrue slightly based on Q2 and Q3, so there’s a onetime benefit to Q4 such that the Q4 run rate would be somewhat higher. So if you encapsulate all those three factors, that kind of leads you to the range where we currently stand.
Scott Gruber — Citi — Analyst
Thanks for the color.
Neal Shah — Vice President, Investor Relations
You’re welcome.
Operator
We’ll now take a question from Doug Leggate with Bank of America.
Doug Leggate — Bank of America Merrill Lynch — Analyst
Thanks. Good morning, everyone. Good morning, Scott.
Scott Sheffield — President and Chief Executive Officer
Hi, Doug.
Doug Leggate — Bank of America Merrill Lynch — Analyst
Scott, you had previously talked about $5 billion of cumulative free cash flow over a five-year period. I’m curious with the significant reduction in well costs you’ve shown here, what you were assuming in that $5 billion number. I’m just curious how you see that free cash flow visibility today under the same price deck.
Scott Sheffield — President and Chief Executive Officer
No, the number really hasn’t changed, Doug, since my announcement in September at the Barclays conference. So the number is still above — look, it’s a little over — we’re rounding off to $5 billion in free cash flow, and that’s in $55 WTI flat during that time frame. Obviously, more bullish, especially with U.S. shale essentially slowing its growth significantly going into 2020. Once we get through the Coronavirus demand issues, I’m more optimistic that we’re going to see a much higher price deck over the next five years, and that number will increase substantially. And as we go out over time, that number will increase even in a flat pricing market because the first couple of years, it’s a little bit lower, and then it increases significantly as we get in the year 2022 through ’23. ’24, the number keeps increasing significantly.
Doug Leggate — Bank of America Merrill Lynch — Analyst
Thanks for the color. My follow-up is just a couple of things you mentioned in your prepared remarks about DrillCo on the water still under evaluation. I just wonder if you could just bring it up-to-date as to how you see the potential for additional non-core, I don’t want to say divestments, but initiatives to release additional value, especially from your longer-dated acreage, if you could bolt-on for that? Just remind us what the invested capital in the water business is as of today. And I’ll leave it there.
Thanks.
Scott Sheffield — President and Chief Executive Officer
In regard to the water, as I stated before, we do not want to trade cost. I think most of the companies that are doing water deals, they’re doing disposal deals, and they’re basically trading — they’re bringing in capital or cash for the balance sheet, and their operating costs are going up. And so we just don’t want to trade cost, and that’s why we’re taking more time, and we won’t make a decision until late 2020. So we just do not want to trade cost and see an increase in our LOE cost.
Joey Hall — Executive Vice President of Permian Operations
And Doug, in terms of the dispositions, I think we did in 2019. Similarly, we’ll look to opportunities to continue to monetize long-dated and non-core inventory in an effort to pull that value forward to shareholders, but they’ll have to be when they come to fruition. So there’s nothing in the docket. We’ll continue to look at them.
Scott Sheffield — President and Chief Executive Officer
As you know, it’s a tough market out there.
Doug Leggate — Bank of America Merrill Lynch — Analyst
I was going to say, how is the appetite for acreage deals at this point? Is it pretty quiet, or how would you characterize it? And I’ll leave it there. Thank you.
Rich Dealy — Executive Vice President and Chief Financial Officer
I’d characterize it pretty quiet. I think as the activity levels, they’re strategic in nature, what you’ve seen is people are doing deals that are blocking up acreage similar to in trades. And so it’s just — they can drill longer laterals.
Doug Leggate — Bank of America Merrill Lynch — Analyst
Thanks, guys. Congrats on the quarter.
Scott Sheffield — President and Chief Executive Officer
Thanks.
Rich Dealy — Executive Vice President and Chief Financial Officer
Thanks.
Operator
We’ll now take a question from Arun Jayaram with JP Morgan.
Arun Jayaram — J.P. Morgan — Analyst
Yes, good morning. Scott, I was wondering if you could, perhaps, elaborate on details of the target agreement and how this will impact, call it, the go-forward financials as you’re no longer going to be incurring that CapEx?
Rich Dealy — Executive Vice President and Chief Financial Officer
Hi, Arun, it’s Rich. I’ll tackle that one. We’ve been working with targets, Scott mentioned, for a number of months on our non-continued agreement that we recently completed. So with that agreement done, they will fund the capital going forward on 100% — and they’ll get to 100% of the revenue on new plans, but we’ll still retain our cash flow from the existing plants. So the benefit that we show in LOE and have been showing will continue from our existing ownership in those plants that we invested in, in the past, but Tier 1’s target will take the revenue from that.
Arun Jayaram — J.P. Morgan — Analyst
Great. And just maybe a follow-up to Scott’s question on the variable dividend. What is the path from here? You’re going to be evaluating this with your major shareholders. Scott, what are your philosophical views on this? And if you did decide this year to shift to a variable dividend, call it, distribution type model in addition to the base dividend, what are you thinking about in terms of timing of implementation?
Scott Sheffield — President and Chief Executive Officer
Like I said, Arun, I mean, the first thing — the first comment is that I’m going to say most, maybe 75% to maybe as high as 90%-plus of shareholders that I’ve talked to and will talk to, they prefer dividends over share buybacks. So I’m starting with that premise. Secondly, we don’t want to get the base too high as we have seen with major oil companies, and we have seen with the refining industry as to where the E&P industry can’t support it. So that leads to an alternative when you have $5 billion plus of excess cash flow.
And I think we’re generating — right now, our dividend payout is roughly $360 million a year times five years. So let’s say $1.8 billion, close to $2 billion, so we’re paying out $2 billion already with our dividend of the $5 billion. So we got $3 billion left to pay out under that price scenario, and so that leads toward a variable dividend. We got a fluctuating in commodity price market. And the question is how much of that and the timing of it and when to pay it out, and we’re still working through the mechanics. We’re learning about how other companies do it in other industries, and we’ll be speaking with people over the next several weeks about how to put it forward.
Arun Jayaram — J.P. Morgan — Analyst
Great. That’s helpful. Thanks a lot, Scott.
Operator
Your next question comes from Jeanine Wai with Barclays.
Jeanine Wai — Barclays — Analyst
Hi, good morning, everyone. My question is on your FT agreements.
Scott Sheffield — President and Chief Executive Officer
Good morning.
Jeanine Wai — Barclays — Analyst
My question is on your FT agreements. I believe Pioneer has now well over 200,000 barrels a day of firm transport to the Gulf Coast, and I think that’s supposed to grow over time with production, maybe not exactly in next step, but it would kind of keep pace. I’m not sure if I’m thinking about that credit lease or any color would be helpful. But I guess what I’m getting at is the WTI Brent spread has been narrowing relative to where it’s been, say, over the past two years or so, and you’ve got some kind of spread that you need to break even on your contracts. So I just wanted to check in to see if there is any appetite to revisit the amount of incremental FT you take on from here on out over the medium or the long term.
Rich Dealy — Executive Vice President and Chief Financial Officer
Yes, Janine, you are correct that we are moving about 220,000 barrels a day. That does grow over time to over 300,000 barrels a day that matches our growth profile going forward FT. I still think that moving it to the Gulf Coast is, long term, will be advantageous. We’re getting into higher-priced markets where we can get Brent pricing for it yesterday.
It’s kind of a neutral breakeven proposition. But for the year, we’ve made $283 million, so I think there’ll be times it still is advantageous to get to higher-priced markets. So I don’t think we’re going to change that strategy. I think in general, with the differential between Midland and Brent prices being $4 to $5, it’s breakeven-type transactions. But we are making sure that we’re available in there and we could benefit when we see price spikes in the future.
Jeanine Wai — Barclays — Analyst
Okay. Great. Thank you for taking my question.
Operator
We’ll now take our next question from Michael Hall with Heikkinen Energy Advisors.
Michael Hall — Heikkinen Energy Advisors — Analyst
Thanks. Appreciate the time. Just kind of curious as you think about efficiencies and all the costs improvements that you rolled through the system in 2019 kind of set yourself a pretty high bar there, how do you think about further efficiency gains in 2020 and beyond? What can really move you up from here? Or are we really just kind of looking at incremental changes? And what sort of key initiatives you have in place for further improvements in 2020?
Joey Hall — Executive Vice President of Permian Operations
Good morning, Michael. This is Joey. Yes, I think as you pointed out, that whenever you have a year where you get almost 25% efficiency gains in one year and 30% cost improvement, it’s not reasonable to expect that you would duplicate that to following year. And I think one of our slides basically references the trajectory, we shouldn’t expect to be the same.
Having said that, though, that doesn’t mean that we’re not still being relentless about focusing on those initiatives and continuing to drive our cost down, and we continue to do so even as we move forward, we see efficiency gains every day. But like you said, we shouldn’t expect to see a similar step change, but as for what are we going to focus on, and we’re going to continue to focus on the things we’ve been focused on. And that’s primarily just looking at how many efficiency side, lean manufacturing methodologies and being relentless with KPIs and measuring what we’re doing out in the field and trying to understand better, more effective ways to go about that, continuing to leverage technology as it develops through our service companies and through our internal efforts and taking on those kind of things. We’re trying to make our practices consistent all across the field, taking kind of the Southwest Airlines methodology with where any pilot can fly any plane and having consistency across our drilling rigs and frac fleets.
So just a combination of all those efforts leads me to believe we still have several bites of the apple, but to expect that it would be similar to what we saw this year is probably not reasonable.
Michael Hall — Heikkinen Energy Advisors — Analyst
That’s helpful. And I guess as a follow-up on a similar topic then. I know you’ve talked about for a long time or late last year, plus two to three wells, the — sorry, two to three rigs of incremental rigs to maintain or sustain that mid-teens growth in oil, is that something that maybe over time that the required rig adds gets muted or any evolution in that, I guess, as you think about 2021 and beyond?
Joey Hall — Executive Vice President of Permian Operations
Yes, Michael. I know that we always try to communicate and use things like rig adds and frac fleets and POPs as proxies to determine future performance. But I think stating the obvious, when you have a 25% improvement in cycle time in one year, you kind of changed that mentality. And frankly, my team is focused on trying to do the same amount of work with less equipment. So like you said, when you have — or like I said, when you have a 25% improvement, that implies do you need 25% less equipment? So it’s getting more and more difficult for us to explain our business based on rig adds. Having said that, though, that’s still kind of our mentality that we’ll continue to focus on the growth and our expectation would be based on current efficiencies at two to three rig adds per year would be kind of the measure by which you should see our activity increase. But those numbers change by the day.
Michael Hall — Heikkinen Energy Advisors — Analyst
Fair enough. I appreciate it. And solid work.
Operator
We’ll now take our next question from John Freeman with Raymond James.
John Freeman — Raymond James — Analyst
Good morning. You’ll show the average pad size in 2020 moving up a little bit to four wells per pad. Is the well spacing still similar to what you all kind of characterized in the past of kind of around that 850-foot spacing?
Joey Hall — Executive Vice President of Permian Operations
Yes. John, whenever we talk about increasing pad sizes, that’s really not a reflection of well spacing. It’s more a reflection of doing more stack developments. So the short answer to your question is that does not imply any change in our well spacing. Our well spacing is basically staying in the same area, 800, 850 feet for the Wolfcamp zones.
John Freeman — Raymond James — Analyst
Okay. And then just the follow-up, should we anticipate that the pad size sort of continues to kind of creep up in the subsequent years? Or is kind of four wells per pad about the right number?
Joey Hall — Executive Vice President of Permian Operations
No. I would expect, as we increase the amount of stack developments that we’re doing and co-developments that we’re doing, that you would see that increase in time. A good example is, last year, I think 35% of our targets were single-zone targets, and this year, that’s down to 15%. And we’ll continue to drive that down as we kind of hone on in our development, and so you’ll see the number of wells per pad creep up over time.
John Freeman — Raymond James — Analyst
Thanks. Appreciate it.
Operator
We’ll now take a question from from Joseph Allman with Baird.
Joseph Allman — Baird — Analyst
Good morning and thanks for all the comments. My question is about natural gas and NGL’s, not the most important part of your portfolio but still important. What assumptions do you make about, say, Waha gas prices going forward? Do you assume basically close to zero? What assumptions do you make about NGL prices, and what do you do to maximize the value of those assets as production increases?
Rich Dealy — Executive Vice President and Chief Financial Officer
Yes. Joe, I think the big thing on natural gas is we have very little gas that’s now exposed to Waha, virtually all our gas is either going out west and getting based on a Socal index or going to the Gulf Coast on a Henry hub or NYMEX index, so we’ve made steps to make sure that we’re not really subject to Waha. Yes. I think, as you say, until a bunch more pipes get built, that Waha is going to be low. So I just think that we’re focused on getting out of basin and getting the higher-priced markets, what the longer-term look at LNG and moving it international like we’ve done on oil. On NGLs, how do we make sure that we are NGLs are processed at Mont Belvieu, but given what’s happened with the amount of liquids that are getting to Mont Belvieu and given the weather that we’ve had in winter and just lack of domain for it, I expect NGL prices still to be weak for a while. They were good in the fourth quarter — better in the fourth quarter, and they’ve fallen back some here in the first quarter.
Joseph Allman — Baird — Analyst
That’s very helpful. And then just as a follow-up, Scott. I know you made comments about your bullishness on oil-related to the slowdown of shale growth. But could you just give us your kind of macro view kind of over the next several months and into the next couple of years?
Scott Sheffield — President and Chief Executive Officer
Yes. So I think, I mean, OPEC really had to go into the coronavirus. So Brent was up to $65 and WTI was up to $60. So coronavirus hit as that is peaking. As we get into the summer months, I’m confident that the price will be up another $5, and it should stay there. Most of the non-OPEC fields are coming on this year, very little non-OPEC fields coming on in ’21, ’22, ’23, ’24. And that’s why I’m a lot more bullish when we go to price. Bullishness, I hope it doesn’t go up too much, but somewhere in that $65 to $70 for Brent.
Joseph Allman — Baird — Analyst
Very helpful. Thanks for the comment.
Operator
We’ll now take a question from Charles Meade with Johnson Rice.
Charles Meade — Johnson Rice — Analyst
Good morning to you and your whole team there. I wonder if we go back to — you touched a little bit — you made a few comments about the DrillCo, but I think you said nine wells. Is there anything else you can offer about how big that was, whether it’s four sections, 10 sections? And are we getting the right feel that we shouldn’t look — or in the current circumstances, we shouldn’t look for a repeat of that?
Rich Dealy — Executive Vice President and Chief Financial Officer
Charles, this is Rich. I think I would — we need to execute it first. And so this DrillCo is in our southern part of the acreage, and it will start in the second quarter of this year. And so I’d say, let’s just wait and see over time. And as we get that one down, then we’ll see what may be next.
Charles Meade — Johnson Rice — Analyst
Okay. And then this is, perhaps, for Joey. Going back to the pad size, bumping up to four on average this year, just two questions on that. One, what’s the dispersion around that mean? Or maybe asked the same thing differently, what percentage of your pads are going to be four-well pads? Is that kind of a truly representative thing? And then should we be on the lookout for anything different as those bigger pads roll through your operations and show up in financials?
Joey Hall — Executive Vice President of Permian Operations
So on the first part, that average is made up of — we still have a relatively significant portion. I can’t remember the exact percentages, but we still have quite a few three-well pads. I would say, four-well pads, five-well pads and six-well pads are growing in percentages year over year. I think for this year, four-well pads will be the predominant percentage and then slowly followed by the five- and six-well pads.
As for how would that show up in our financials, of course, the more activity we can put on one location, that is an opportunity to continue to drive down well cost. One of the other aspects of this that may seem a little bit more subtle is our typical cycle time for a three-well pad is about 180 days. Of course, whenever you add that fourth well on, that increases your cycle time. So that may have the opportunity depending on the dispersion of the pads throughout the year to make production a little bit lumpier and the timing of bringing those pads on, create some noise in the production.
But overall, it’s a net positive because it also goes back to our development strategy and doing co-development, which helps us with increased well productivity. So as we move in that direction, it just shows certainty in our development plan. And it does nothing but reap great benefits. The only downside being to slightly longer cycle times.
Charles Meade — Johnson Rice — Analyst
Thanks for the detail.
Operator
We’ll now take a question from Scott Hanold with RBC Capital Markets.
Scott Hanold — RBC Capital Markets — Analyst
Yes, thanks. You know, I take a look at your LOE cost. It came in below expectations or at least below your guidance. And part of that is that gas processing, I guess, recovery, I’ll call it, that you all get. Could you give us some color on how you see that going forward through this year, especially now that you’re going to be nonconsenting on some of the target stuff? And really, what are the ebbs and flows to that? And is that in some of your forward guidance?
Rich Dealy — Executive Vice President and Chief Financial Officer
Yes, we built it into our guidance range for production costs. That natural gas processing benefit really is dependent on where NGL prices sit for the most part and, to a lesser extent, residue gas because most of the contracts out there are driven by POP contracts. So that’s why when you look across the bottom of that chart, it ebbs and flows, really with NGL and gas prices. But going forward, I don’t expect it to meaningfully change over the next few years just because we’re going to bring on one plant later this year, the gateway plant, that Targo is bringing on, and so they just won’t change a whole lot going forward other than tracking with commodity prices, NGL, and gas prices.
Scott Hanold — RBC Capital Markets — Analyst
Okay, Okay. That’s appreciated. And on sticking, I guess, on NGLs. And your price realization on NGLs were really strong, I guess, relative to a lot of your peers. Again, is that attributed to some of the gas processing and the better NGL yields you’re getting on these new plants?
Rich Dealy — Executive Vice President and Chief Financial Officer
Definitely, we’ve seen our NGL direction up. Obviously, the new plants have have higher recovery levels, but they’ve also tried to increase the recovery levels across the system because NGLs are better priced than Waha gas, where a lot of that gas ends up being sold other than the stuff that we take in kind from a processor standpoint. So unfortunately, first quarter, ethane and propane prices are a little bit lower, so we’re not going to have quite the realizations in the first quarter that we had in the fourth quarter.
Scott Hanold — RBC Capital Markets — Analyst
Yes. Is there a way to explain why you guys were in the fourth quarter strong relative to some of your peers? Is there something unique with the fourth quarter or just how you guys sell yours?
Rich Dealy — Executive Vice President and Chief Financial Officer
Nothing unique that I can point to, and I’m not familiar enough with what the peers have reported or how they marketed. So I can’t speak other than, given our size and scale, maybe we have a little bit better POP contract.
Scott Hanold — RBC Capital Markets — Analyst
Thanks.
Operator
We’ll now take our next question from Brian Singer with Goldman Sachs.
Brian Singer — Goldman Sachs — Analyst
Thank you. Good morning. I wanted to pick up on the topic of cost efficiencies from here. And Scott, big picture, when you came back as CEO, you noted the Pioneer’s well costs in the Permian were too high and you subsequently lowered costs and improved efficiencies. Are you where you want to be now? And do you now view your well cost position as sufficiently competitive based on the size, scale, and quality of Pioneer’s acreage?
Scott Sheffield — President and Chief Executive Officer
Yes, Brian. I’ve seen some offset data from other peers, and this is the first — we’re actually beating some of the Permian peers now, especially in the Midland Basin. I know we’re beating Delaware, but you can’t really compare Delaware since it’s a higher cost area. But in looking at some of the Permian Basin companies and their disclosures, we are definitely as competitive or better than most companies today. And I still anticipate, as Joey said, we’re going to continue to achieve more reductions. So in our long-term plan, we show a certain number of rigs. I don’t think at the end of the day, we’re going to be adding two to three rigs every year to get the same growth rate over the next 10 years.
Brian Singer — Goldman Sachs — Analyst
Great. And then my follow-up is on that mid-teens growth longer-term plan and the point that you bring out on Slide 8. You talked about the free cash flow and ROCE maximization as your focus, and I wanted to ask about one of the other points, which is execution. How do you — when you think about trying to continue to grow from an already decently high base, mid-teens growth, how do you focus on the short and long-term risk execution? What do you see in 2020 as key potential for upside and downside risk from an execution perspective that you and the team are focused on?
Scott Sheffield — President and Chief Executive Officer
I think we’ve taken the risk off the table. So I mean, to me, I see very little risk at all. We’ve taken it off the table. We’ve proven it after overspending $850 million in 2018 and underspending $700 million in 2019. It’s one of those items, I think, that everybody is focused on it. Everybody’s held accountable, so I don’t even look at it as a risk anymore. And in regard to the free cash flow and capital, just to make a further point, right now, I think we have about $1.8 billion of the $5 billion spoken for, $5 billion-plus free cash flow, and that’s in the base dividend. We’ll continue to allocate that to buybacks and also to potentially that variable dividend.
Brian Singer — Goldman Sachs — Analyst
Great. Thank you.
Operator
We’ll now take our next question from David Deckelbaum with Cowen.
David Deckelbaum — Cowen and Company — Analyst
Good morning, everyone. Thanks for the time. Scott, I just wanted to follow up on the considerations around your water business. Outside of financial market arbitrage, what would be some of the variables or considerations that would prevent you from monetizing this business?
Scott Sheffield — President and Chief Executive Officer
Well, we don’t start off with — I think most of the peers that have done — my opinion is that their balance sheet is still too high. They have too much debt, and they’re using the proceeds to reduce the balance sheet. So we don’t need to do it for that reason. So we have to decide what multiple if we do sell a portion of it. And in fact, we’re probably going to rule out selling. I think I’ve already said this. We’re going to roll out selling the entire thing. It’s too important for us. It’s a question whether or not we bring in a long-term partner as we continue to build it out. And so it’s just something that we’re going to make a decision on by the end of this year.
David Deckelbaum — Cowen and Company — Analyst
Thanks for that. And then my follow-up is just, this year, you guys are having that consistent well mix of Wolfcamp A and Wolfcamp B is about 80% of your wells turn in. At what point in the future you start seeing a greater contribution from some other zones? You all have made some headway in Wolfcamp B over the last couple of years of the delineation effort. Is any color you can provide around just what that development looks for and now there’s a shift away from Wolfcamp A and B, to some extent, in the other year?
Joey Hall — Executive Vice President of Permian Operations
Yes. David, we prioritize our portfolio every year based on returns. And as far as looking from last year to this year, the major shift that you’ll see is kind of a more equal percentage of Wolfcamp A and Wolfcamp B together. That’s primarily because of the fact that we’re focused on co-development, continuing to deliver significant number of Jo Mills because they have strong returns. Wolfcamp D will continue to be a small part of our portfolio at this point in time. We’re focused on understanding the development strategy for the Wolfcamp D and focusing on getting the returns up. And whenever we feel like we’ve got that perfected and got the returns similar to what we’d see in the Wolfcamp A, B and Jo Mills and lower Spraberry shale, we’ll start to bring those in. But the short answer is we’re not really doing it just based on portfolio. We’re doing it to make sure we maximize the returns that we can for each and every year.
David Deckelbaum — Cowen and Company — Analyst
Thank you, guys.
Operator
And that concludes our question-and-answer session for today. I’d like to turn the conference back over to Mr. Sheffield for any additional or closing remarks.
Scott Sheffield — President and Chief Executive Officer
Thank you all very much. We look forward to the call next quarter, and hopefully, you’ll get to see a lot of you all over the next few weeks in several months as we get out on the road. Thanks again.
Operator
[Operator Closing Remarks]
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