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Diamondback Energy Inc
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Good day and thank you for standing by. Welcome to the Diamondback Energy Fourth Quarter 2021 Earnings Conference Call. At this time all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions] Please be advised that today’s conference is being recorded. [Operator Instructions] I would now like to hand the conference over to your speaker today, Adam Lawlis, Vice President of Investor Relations.
Thank you, Earlis. Good morning and welcome to Diamondback Energy’s fourth quarter 2021 conference call. During our call today, we will reference an updated investor presentation, which can be found on Diamondback’s website. Representing Diamondback today are Travis Stice, Chairman and CEO; Kaes Van’t Hof, President and CFO; and Danny Wesson, COO. During this conference call, the participants may make certain forward-looking statements relating to the company’s financial conditions, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company’s filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliation with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I’ll now turn the call over to Travis Stice.
Thank you, Adam, and welcome to Diamondback’s fourth quarter earnings call. 2021 was a great year for Diamondback and our industry with higher product prices allowing the vast majority of our industry to one repair and improve balance sheets quickly; two, accelerate returns to shareholders; and three, make significant progress on environmental objectives. At Diamondback, we reduced our absolute debt by $1.3 billion, increased our base dividend every quarter, initiated a return of capital framework and announced ambitious environmental goals designed to help us earn our environmental license to operate. In the fourth quarter alone, buoyed by commodity price strength, Diamondback generated $772 million of free cash flow with production and capital both positively exceeding expectations. We returned 67% of this free cash flow to stockholders, which was above our commitment to return at least 50% of our free cash flow to shareholders quarterly. This return was made up of $106 million allocated to our growing base dividend, now at $2.40 a share on an annualized basis, which represents a current yield of approximately 2% and $409 million in share purchases as we bought back nearly 3.9 million shares at an average price of just under $106 per share. We are at the beginning of an incredible period of value creation for the industry. And I’m confident that the capital discipline demonstrated by us and our peers in 2021 will continue putting returns and therefore shareholders first. We believe this is the best near-term path to equity value creation as our shift from a consumer of capital to a net distributor of capital cements itself as our long-term business model. Two months into 2022, economies are rapidly reopening around the world stoking demand, which we believe to be close to if not above pre-pandemic levels. On the supply side, we are witnessing some underperformance from OPEC+ to meet this increasing demand, calling into question spare capacity with global inventory numbers now approaching 2010 to 2014 levels. We cited both global oil inventories and OPEC spare capacity as impediments to any discussion around U.S. public company oil growth, and those issues appear to have subsided for now. However, the global balance remains tenuous at best with up to a million barrels per day of additional Iranian barrels potentially coming online sometime this year and U.S. growth expectations continuing to climb higher led by private companies and more importantly or more recently measures. Both of these supply factors could be bearish signals for oil, therefore Diamondback’s team and board believe that we have no reason to put growth before returns. Our shareholders, the owners of our company agreed. And as a result, we will continue to be disciplined, keeping our oil production flat this year. As such our plan for this year is simple. Maintain oil reduction of approximately 220,000 barrels per day by spending between $1.75 billion and $1.9 billion. At current strip pricing, this production and capital spend equates to nearly $4 billion of free cash flow, which to our returns framework gives a minimum of $2 billion of cash back to our investors. At the same time, we are committed to permanent returns to our investors, which is why we continue to lean into our base dividend, increasing it again by 20% this quarter. Our growing base dividend is our primary means of returning capital and we’ve increased it by quarterly CAGR of over 10%, since it was initiated in 2018. Today, we have line of sight to get our dividend to $3 a share by the end of this year, if market conditions remain favorable, which would mean 25% of our 2022 distributable free cash flow would be allocated through this constant predictable form of shareholder return. History has taught us that oil is a volatile commodity and that the macro environment will not always be this favorable. So we continue to work towards protecting our base dividend down to $35 WTI with a view that this dividend is really just a form of debt and if plus our maintenance capital budget have to be protected to the extreme downside. By continuing to focus on our fortress balance sheet and layering on our strategic derivative positions to our hedge book, we are confident in our ability to perform in any environment. While the base dividend is the primary tool of returning capital, we will also utilize share repurchases and potentially variable dividends to reach at least 50% of distributed free cash flow on a quarterly basis. We continue to repurchase shares opportunistically, taking advantage of volatility while generating returns on these repurchases well in excess of our cost of capital at mid-cycle commodity prices, which today is assumed to be around $60 WTI. Through the end of the fourth quarter, we’ve spent $430 million or 22% of the $2 billion program our Board authorized last September. If the free cash flow returned through our base dividend and repurchase program does not equal at least 50% of free cash flow for that particular quarter, then we will make our investors hold by distributing the rest of that free cash flow via a variable dividend. This strategy gives us the ability to be flexible and opportunistic when distributing capital above and beyond our base dividend and most importantly allows at least 50% of free cash flow to be returned. However, it is important that the Board also retains discretion on what to do with the other 50% of the free cash flow generated. As was the case in the fourth quarter, we have the ability to distribute above and beyond our 50% threshold if we feel comfortable with our balance sheet and associated cash balance and do not have a use for excess cash, we will return that cash aggressively to shareholders. Some quarters, we will distribute 50% of free cash flow, but in others we will have the ability to return more, just like we did in the fourth quarter. Going forward, we fully expect to differentiate ourselves not only by our returns framework but more importantly through our consistent execution in the field. Last year, our clear fluid design lowered our average drilling days in the Midland Basin by approximately 35%. That’s an astounding achievement for our drilling department. On the frac side, our simul-frac operations continue to reduce our time on pad as we are now averaging 3,200 feet per day with our four-well simul-frac design. As we’ve laid out in our investor deck, these operational efficiencies have helped us mitigate the substantial cost pressures we’ve seen related to consumables and labor and as we noted last quarter, these gains will be permanent, giving us more variable cost control than our peers due to these industry-leading drilling and completion times. Now when you bake in these cost increases and offset them with our efficiency gain, this equates to about 10% of additional capital spend year-over-year, which is baked into our guidance. We will try to offset this inflation by doing what we do best, innovating, implementing new technology and drilling more efficient and better wells. As mentioned, we were able to offset a vast majority of pricing increases we faced last year through this type of innovation. And we’re confident we can maintain our best-in-class capital efficiency and cost structure this year. At the same time, we are fortunate to have multiple pieces of our capital cost structure locked in with contracts and dedications like our water and sand supply. As the rig count in the Permian climbs, we will continue to work to control other components of our cost structure, particularly services, labor and consumable products while continuing to be the leader in cash margin and capital efficiency. Finally, I’d like to close by detailing the strides we’ve made in our environmental, social and governance practices. To begin, we met four of our five environmental goals in 2021, which had a 20% weighting in management’s short-term compensation this year and included specific targets related to flaring, water recycling, GHG emission intensity, produced liquid spills and total recordable incidents. Unfortunately, we did not meet our expectation of flaring less than 1% of gross gas produced. While we met this goal on legacy Diamondback acreage, which was how the goal was set, we missed our target when incorporating our acquired QEP assets, which included the QEP Bakken asset we divested in October. We will continue to improve our takeaway on the acquired Permian acreage and partner with our midstream companies to not only structure contracts then incentivize takeaway in price-agnostic environments, but also apply performance-based incentives and penalties related to flaring. All of our progress in 2021 positions us well to hit our long-term goals of reducing our GHG and methane intensity by 50% and 70%, respectively, by 2024, and recycling over 65% of our water and eliminating all routine flaring by 2025. These environmental goals hit close to home as we hold the unique title of being the only publicly traded E&P headquartered in Midland, in the heart of the Permian Basin. As such, we feel an enormous social responsibility to better the community in which we live, work and play. We recently committed $2.5 million to a complete redesign of Midland’s largest public park as well as $500,000 for Midlands Meals on Wheels program. Arguably more important, however, our employees continue to give their time to sponsor and host camps, reading and instructional programs and public work projects. I’m incredibly proud of our team’s efforts. 2021 is a great year for the company. We generated record free cash flow and distributed over 30% of it to shareholders, strengthened our balance sheet by substantially reducing our absolute debt load and continued to produce one of the cleanest and most cost-effective barrels in the industry. Looking ahead, we are confident in continued consistent operational execution and the ability to generate peer-leading returns. With these comments now complete, operator, please open the line for questions.
Thank you, sir. [Operator Instructions] Your first question is from Arun Jayaram from JPMorgan.
Good morning, Travis and team. I wanted to just get some broader thoughts on your plan, Travis, to allocate free cash flow in 2022, obviously, have buybacks, variable dividends and debt, while I’m assuming you want to keep some powder dry for A&D opportunities. But with the stock trading above the valuation of the stock, assuming a mid-cycle deck, we think you’re probably going to pivot a little bit more to variable dividends, but I wanted to get your thoughts on that and how the $4 billion, if the strip holds could be allocated this year?
Sure. Arun, it’s good visiting with you again. Listen, I’ll tell you to the penny how much on share repurchases we bought in May, if any. But what hasn’t changed, Arun, is our commitment. Whatever portion of our free cash flow that we don’t spend on repurchases, we’re going to return that free cash flow to our shareholders. Look, when it comes to share repurchasing, we view that as just like any other investment decision, drill a well, M&A activity. We do so, like you mentioned, at a mid-cycle oil price, which for us is around $60 a barrel. And it has to generate a positive return. And when you go back and look at what oil price has averaged since the fall of 2014 has averaged $53 a barrel. And if you can guarantee me that the price of oil is going to be $90 or above, then I’ll tell you that our shares are undervalued. But we’re going to be disciplined. We’re going to be opportunistic when it comes to our share repurchase programs just like any other form of capital allocation and what we don’t repurchase in shares we’re going to return back to our shareholders in the variable dividend every quarter.
Yes. I think on top of that, Arun, we certainly want a fortress balance sheet. I think there’s some stuff for us to do with our 2024 and 2025 notes this year, pay down debt when things are good. And I think that could open the door for higher returns. I think the key is 50% of free cash flow is going back to the shareholders. And if we don’t have anything to do with the other 50%, it’s coming back as well and we proved that in the fourth quarter.
Great. And I had one follow-up on the Permian in general. Just thinking about the industry, what are the potential headwinds for future growth will be gas takeaway, current scrapes are just around 14 Bcf a day. We estimate there is about 17 Bcf a day of takeaway capacity. So I wanted to get your thoughts, Travis, your net production is approaching 0.5 B and how do you think Diamondback is positioned to manage this tightness that could occur in late 2023 or early 2024?
Yes. I mean I think, Arun, unlike the past, I think we have the size and scale now to contribute to pipelines and make sure it happens. We’re certainly doing our part, not growing. I wish other people would grow less in the Permian too but that’s a different topic. But generally, we committed to the Whistler pipeline, just announced that this -- with this earnings. And that was with our WTG commitment on gas gathering and processing, committed to the BANGL pipeline, which is NGL takeaway. And really just trying to put our balance sheet to work to make sure pipeline capacity is strong coming out of the basin. I think we’ll see some announcements here pretty soon. Saw a couple of things last week on new pipes, but I think generally the industry is aligned that we can’t go back to the way we were when it comes to flaring. And particularly with gas prices up, we should all be incentivized to make sure gas flows out of the Permian. So it’s going to be tight if growth continues through 2023, but I’m pretty optimistic on 2024.
Okay. So are you looking to add capacity on those two pipes, one of the two pipes?
Yes, we would. You have to have taken kind rights to be able to do that. And so we’re putting a lot of pressure on our midstream partners to either relinquish our taking kind rights to us so that we can contribute to the pipeline like we did on the Whistler pipe, putting our balance sheet to work or incentivizing them to contribute themselves. So -- that’s a little bit of a game of chicken with our G&P’s. But I think message is we both need to figure this out as a group and we would be willing to put our balance sheet to work to make it happen.
Great thanks a lot.
Thank you, Arun.
Thanks, Arun.
Your next question is from Neil Mehta of Goldman Sachs.
Good morning, team and congratulations to everyone on the new promotions over at Diamondback. The first question is the hedging strategy. Travis, you talked about a long-term $60 WTI view, curve’s obviously trading well through that. Does it make sense to opportunistically layer in hedging and thereby lock in more of the capital returns? Or do you think, given the strength of balance sheet, you can run the business more open?
As our balance sheet strengthens, I think your comment about running the business a little bit more open makes sense. But having said that, though, we have to make sure that we protect the extreme downside. Look, the impossible happened in 2020. While we don’t ever think that’s going to happen again, we want to make sure that we’ve got insurance to provide accordingly. I think we try to do deferred premium puts as our preferred hedging strategy, which kind of sets that protection in place for us while accomplishing, giving our shareholders all the upside on price as well.
Yes. I mean we hope for the best but prepare for the worst. And preparing for the worst is buying puts at $50. The balance sheet doesn’t blow out, dividend is well protected, still our free cash flow above that and try to leave as much upside for the best as possible.
Yes. That makes sense. The follow-up is Travis, you famously said, I think it was last August that your view was it was a seller’s market. And stock has obviously done very well since then and your equity value has strengthened. What’s your thought on the M&A environment in the Permian? Do you view Diamondback as a logical consolidator. And how do you think about the time line of that, especially with oil above mid-cycle prices?
Yes, Neil, that’s a good question. And it’s really hard for me to see how kind of the excess of G&A that still exists in the Permian, how all of that gets consolidated. I wish I could articulate clearly what the catalyst is going to be that allows consolidation to occur, because it’s needed in our industry. That being said, there’s a lot of companies that had one foot in the -- whistling through the graveyard with one foot in the grave. And now a couple of years later, oil is at $90 a barrel and they’re expecting to sell out and get value on future cash flows at $90 a barrel. And as I mentioned, it’s the same strategy on our share buybacks, right? If the mid-cycle oil price is $60 a barrel, then it’s going to be hard to close the spread between bid and ask on the much-needed M&A activity that has to occur here in the Permian. So, while I’d like to think Diamondback could create unreasonable value for our shareholders, like we did with the QEP and Guidon acquisition. It’s hard with these frothy expectations on the oil price that we’re seeing today.
No, that’s very clear. Thank you, Travis, Kaes.
Thank you.
Thanks, Neil.
Your next question is from Neal Dingmann of Truist Securities.
Good morning guys, thanks for the time. My question maybe for you, Kaes, is my first, a little different angle on shareholder return. What I’d say there is -- while I’m glad to see you all have really not gotten caught in this group think of suggestion you have to pay out all your free cash flow. The question I’m getting from the investors is, how do you all think you got to show investors that you’ll continue to be the best allocators of capital that you have. And Kaes you mentioned anything is out there on a lot of possibilities with one of those allocation choices at some point include higher production.
Yes, Neil, good question. I think the Street has lost sight of value creation for E&Ps. I get that there’s a lot of cash going back to shareholders. But at the end of the day, if you can generate more free cash flow with the same expectations out of the business, you’re creating more value over a long period of time. Execution is going to matter, metrics matter, controlling cost matters, PDP F&D matters. And for us, all of those inputs create more free cash flow, and that means more free cash flow is going to shareholders, whether it’s 50% of free cash flow in one quarter or 67% and another. We kind of think about this as a partnership. It’s just that the partnership has a commitment to return 50% of free cash flow if we have something to do with the other 50% that creates unreasonable value, we’ll keep it. But we’re not going to sit on cash and we’re going to distribute a ton of cash to partners. Just the only commitment is at least 50% of that cash is coming back.
Great to hear. And then Travis, my second question, probably for you is, I like the Slides 10 and 11 on margins and costs. I’m just wondering specifically, can you give maybe a little more color on the primary driver of that leading cash margin. I mean is it that sort of newish 10-day drilling well design that’s driving that? Or maybe just talk about what you would primarily point to.
Yes, certainly, we’ve got the benefit of the improvements that we made in 2021, as I mentioned, 35% improvement in drill times, and we’re going to get a full year impact of that this year, which is helping us offset the inflationary effects. A couple of data points, Neal, that -- we just -- I just find out about yesterday as we’re getting updated in our weekly meeting, we drilled a well in the Delaware Basin. It’s a 15,000-foot lateral. We drilled it to TD in nine days, which was a record for us and for that area, just an outstanding occurrence. And even on the Midland Basin side, we’ve been drilling the most. We drilled another three-mile lateral, a 15,000-foot lateral in seven and a half days. But what’s amazing about that, and that’s to TD. What’s amazing about that is we don’t spend three and a half days in the lateral. Now we used a rotary steerable and sometimes rotary steerable technology is a little harder to replicate. But that’s what’s possible. So, we’ve got an organization Neal that continues to lean into this variable expense side. And what I can emphasize enough is that that’s ground that’s taken and never given back. When you become more efficient at something that’s always on your side of the table, and it’s for the good guys. So, I know kind of -- that’s a little bit off topic there, but it’s really important to hear that our organization is locked and loaded, and this machine is humming very, very efficiently. And you couldn’t want more -- you couldn’t want a machine humming more efficiently than we are right now in an inflationary environment.
No, I always want to hear those updates. Thanks Travis, thanks, Kaes.
Thanks, Neal.
Your next question is from Derrick Whitfield of Stifel.
Good morning all. Congrats on your quarter and update.
Thank you, Derrick.
Thanks, Derrick.
With my first question, I wanted to focus on the flaring you experienced in Q4. With the full understanding of its importance to you based on your ESG mandate and incentive compensation. Could you speak to the higher-than-expected flaring you experienced? And what steps you guys can take to mitigate that in the future even with your partners?
Yes. If you look on Slide 18, Derrick, we laid it out with quite a bit of detail. And just as an aside, you’ve heard me say this before, our Board expects management to not only lead the industry in environmental measures, but also lead the industry in disclosure. And I think 18 is a pretty good slide. But let me just point to something specifically. If you look in the top right of that slide, it talks about flaring by source. And if you take third-party planned maintenance and third-party unplanned maintenance, that’s 80% of our flaring volumes in 2021. And particularly on the unplanned side, which is something that we’ve just got to do a better job with our business partners on. Now, I said in my prepared remarks, we’ve actually changed contracts where we can that both incentivizes and penalizes flaring performance. So, we’re looking to expand that concept across all of our gatherers, but we’re also intentionally asking our midstream gatherers to help us as an industry on this effort. And that’s part of the reason that we’re calling attention to this to their performance on Slide 18. Now, particular to the miss, I tried to lay that out, we set the goal for our flaring before we bought QEP and Guidon. And we didn’t adjust our goal just because we acquired assets that had much worse flaring statistics than we did. We tried to absorb it. We did absorb it, but it cost us on our annual performance. But that’s -- we felt like that was the right way to treat it. Once the goal is set, we honor it.
Yes. One thing to add is, we also deferred half a million barrels of oil last year. I mean we’re trying to do our part here, Derrick. We deferred 850,000 BOEs, half a million barrels of oil because of flaring. We’re just kind of asking that both sides, midstream and upstream get together to solve this industry issue.
And that shouldn’t be lost, Derrick. That’s a very key point. Think about that. We deferred over a half a million barrels last year just to avoid flaring. And that’s a behavior that represents a substantial pivot for Diamondback and a substantial pivot if our peers follow suit for our industry. And what I believe you’re seeing, Derrick, is you’re seeing environmental stewardship more of -- more companies are viewing it as an operating philosophy as opposed to an expense, which it was historically or hit the volumes. And I think that’s an important narrative for our industry to get out there and push as an operating philosophy, environmental stewardship, particularly around eliminating flaring and eliminating methane emissions is simply the way to operate a business on a full cycle basis. And I hope that makes sense.
It does. And your commitment to it, it’s quite clear. As my follow-up, I wanted to dig in a bit more on the macro side and ask if you could share your expectations for growth in the Permian in 2022 and ask if the growth rates outlined by the majors in the Permian if that’s a concern for you?
Well, look, I pointed out that on a global sense, the supply-demand is pretty tenuous. And even with the announced growth from the majors, I’m not sure that the total barrels that they’re producing are growing into the global equation. So that’s kind of a plus. Now, right here to look out my window, I know that the Permian is running about 300 rigs right now. We’re probably on the way to 350 rigs or 400 rigs by the end of this year. And a large portion of that -- of those rigs have been operated by Permian. But I think some of the growth you’re seeing on a go-forward basis will be from the majors. We’ve already talked about gas pipeline takeaway issues and a little bit on the NGLs, which I think Diamondback has been on our front foot, getting some strategic alliances there, and oil take away is in great shape, but it is going to create inflationary pressures. But that’s what you’re charged to us and all of our industry’s charge is how to manage CapEx in an inflationary environment and not put your shareholder return program at risk. That’s kind of how I think about the total Permian playbook.
Great. And you guys have done a great job with that. So thanks again for your time.
Thank you, Derrick.
Your next question is from Doug Leggate of Bank of America.
Thank you. Good morning everybody. Guys, post the deals, I guess, the cleanup of last year, it looks like you’ve gone through a little bit of an inventory high grading on your latest disclosure. I just wonder if you could kind of walk us through what that looked like. It looks to us that you’re sitting on about a better than 15-year inventory if you define just the core of that slightly longer lateral inventory you laid out today. So, can you just walk us through what that process was, and if I’m thinking about it the right way?
Yes. I mean, generally, Doug, post the deals we do a lot of trades to try to block up, extend inventory, extend laterals, sometimes at the expense of lower working interest inventory that may not be operated or have shorter laterals. So that’s the blocking and tackling piece that we’re very focused on. And second, on inventory, we’ve gone a little wider in both the Midland and the Delaware Basins. I think our updated inventory numbers reflect that in kind of moving towards six wells to seven wells per zone per section in the Midland Basin versus kind of eight being the tightest 660-foot spacing. And the Delaware move into kind of four wells to five wells a section in the primary zones versus six wells. I think what we found is we’re not sacrificing a ton of EUR from that unit by going a little wider, but we are generating much better returns and much better capital efficiency. So, I think the offset from a present value perspective outweighs the loss of a couple of locations.
So is it the right way to think about this on if you guys maintain your ex growth outlook, we’re looking at better than 15 years of drilling. I mean, obviously, I know it’s a little bit too precise. But I’m trying to just think about the longevity of the portfolio strategy with the inventory you have today.
Yes, that’s fair. I will add that -- it’s a small number, but we are completing five less wells at the midpoint in 2022 than we were in 2021. And as the base decline shallows out and we get active on sale of Robertson Ranch, where we have a significant percentage of minerals helping us out, that capital efficiency is going to look a little better here over the coming years.
Okay. My follow-up, I hate to do it, but it’s the variable dividend buyback, balance sheet question. When you pay out a variable, the cash is gone at the top of the cycle, let’s say, M&A opportunities fall by the wayside, let’s assume then you get a correction in oil prices and the cash has been paid out as a variable. I’m just kind of curious, your commentary, you mentioned variable has differentiated you, that you haven’t gone down that path. What should we take from those comments as to how you’re prioritizing setting cash on the balance sheet, continuing to buy back stock if you see intrinsic value or indeed giving out a variable dividend that you don’t really get a chance to get back?
Yes. So it’s really pretty straightforward, Doug. It’s lean into the base dividend, which we’ve shown every quarter since we initiated the dividend back in 2018. And we’re going to get that up to $3 a share if the market conditions don’t change. The second is share repurchases. But again, there’s a calculus that’s involved in an investment decision for share repurchases. So to the extent we can consume 50% of our free cash flow at a good return on share repurchases then that’s what we’ll do. But if we see a dislocation between commodity price, share repurchases, we’ll pivot quickly within the quarter to pay out the remaining, up to 50% -- or at least 50% of the free cash flow in the form of a variable dividend. So in some quarters, it’s at least going to be 50%. And in some quarters, it could be as much as like we did this last quarter, 67% or more. But we’re just trying to maintain at the end of the day, Doug, we’re trying to maintain the greatest flexibility to generate the best shareholder return.
Travis, I apologize. What do you do with the other 50%? You did 67% in the fourth quarter?
Well, right now, we’d like to continue to work on having a fortress balance sheet and having cash on that fortress balance sheet for an inevitable down cycle. So, I think we’re focused on kind of our mid-decade maturities if we can extend some of them, but also pay down most of them. That clears the way for a lot more cash to be put on the balance sheet and then step up the overall shareholder return from there. But I don’t think it’s something we’re there yet, Doug.
Thanks, Travis.
Thanks, Doug.
Your next question is from David Deckelbaum with Cowen.
Good morning guys. Thanks for the time this morning.
Hi, David.
Just wanted to revisit that last point on the balance sheet. You talked about the mid-decade maturities. Is there -- can you remind us, is there an absolute sort of debt target that you have if you’re factoring in a $60 mid-cycle price?
Yes. I kind of think about absolute getting down to $3.5 billion-ish at Diamondback and $1 billion-ish at the subs. So $4.5 million total. I think that keeps you very well protected even at a mid-cycle price turn or so. But more importantly, average maturity getting extended is going to be important because that clears the way for more shareholder returns between now and 2029 when our next big note would be due.
I appreciate that. And then just my second question. The slide where you were referencing cost inflation looked like it rolled up to about 15% overall. The reference point was the third quarter of 2020, where I think we were paying people to stick oil in swimming pools. So 15% seems relatively benign since then. I’m curious what your outlook is on what you can do and what you’re factoring in, in terms of cost inflation into the 2023, 2024 time line. And would you – do you think that there’s still room to offset that with efficiencies? And are you changing how you’re contracting for services right now?
Well, you always want your organization to continue to look for the efficiencies on the variable side. And it’s hard to forecast what those are. But it’s not hard to try to incentivize the culture that looks for those efficiency gains. And what they’re going to look like in 2023 and 2024, I can’t tell you, but I know we’re going to continue to look for it. And I know if past performance is a good indication, we’ll continue to lead the back on these type of efficiencies. Contracting long term for more of the consumables on the fixed side of the equation, those have typically been very difficult for our industry because the time that the operator wants to lock in is the time that the service provider doesn’t. We’re always at odds and ends of the spectrum. So like right now, the consumable guys on the service side would love to lock in these all-time high prices. Operators are reluctant to do so. So Diamondback has the size and the scale to have very meaningful conversation with our business partners on the service side. And we have those quarterly or every six months. And that’s the way that we’ve chosen to manage that relationship. And most of our service providers we’ve had now for over five years, and we’ve got a really good business relationship with them. Look, their margins have to expand. We understand that. But our commitment to be best-in-class and the highest margin remains unchanged as well, too. So it’s not a straightforward calculus, David, that I can lay out for you. But I can tell you that the organization will we continue to lean into it. And I’m very confident certainly for 2022 that we’ll be able to do so.
And one comment on Slide 10, David. Slide 10 tells you exactly what we’re saying, right? The rig line and the stimulation line, rig rates are up, frac rates are up, but the efficiencies that have been gained as seen in the top half of the page means that those pieces of the well costs have not risen like fixed costs like fuel or cement or casing.
Absolutely, and thanks for pointing that out and congrats on all the promotions. Thanks for the answers.
Thanks, David.
Thanks, David.
Your next question is from Jeoffrey Lambujon of Tudor Pickering Holt.
Good morning and thanks for taking my question. Just one for me on ESG. Obviously, a lot of progress made on the initiatives that you set out in September with your sustainability report just looking at that section of the slide deck that you highlighted. I was wondering if you could just talk a bit about what you’re focused on this year. I know you hit on flaring already. And then thinking further out, it would be interesting to hear about what sort of projects you could see yourselves investing in and continue to make progress on offsetting emissions.
Yes. We’ve been pretty clear that we’re committing, I don’t know, $20 million or so per year for the next several years to eliminate flaring and to significantly reduce methane emissions. And tactically, that’s translated on the methane side to overhauling and reconfiguring a lot of our old, mostly acquired tank batteries that have gas pneumatics. I think we’ve got a slide in there that actually points that out. Yes. Gas pneumatics, you can see what that is on Slides 19 and 20. But that’s been the first focus area is the gas pneumatics. And Danny, we’re probably halfway through getting those batteries changed, third to halfway through?
Yes. We kind of laid out the framework to get through them all in three to four years, a couple of years ago. So we’re about halfway through with the battery upgrades and still working on leak detection and repair initiatives, and then flaring is our main drivers of methane emissions.
And then Jeff, on methane emissions, there’s just an amazing amount of innovative technology that’s coming out from the service side. And we’re not – we haven’t picked a winner yet. I don’t know that there’s been a clear winner, but our approach has been to field test all of them. We’ve probably got five or six leading edge technology methane sensors in the field in order to monitor these things, monitor methane emissions in real time. So we’re investing alongside these technology companies on methane emissions. And then as Danny mentioned, flaring is something we’re really leaning hard into and I can’t emphasize enough that we can do everything we can on our side, but if we don’t get our midstream partners on the G&P side to participate it’s going to be very difficult for our industry to meet our goal of reducing or eliminating routine flaring as defined by the World Bank. So there is a reason we’re being pointed in our presentation today about asking to work collaboratively with our G&P partners on the flaring side.
Great. Thank you.
Thanks, Jeoff.
Your next question is from Nitin Kumar of Wells Fargo.
Hi, good morning guys. Thanks for taking my questions. A lot of ground has been covered on the cash return side. But I want to check on the base dividend. You mentioned earlier that it could be about 25% of free cash flow of the return portion of free cash flow in 2022. How are you thinking about it beyond the $3 per share. Is that a good limit? Or could we see more increases in what would drive that?
Well, it really depends on what the market conditions look like at that point. I mean we can’t continue to grow at 10% per quarter forever, right? At $3 a share, that’s over $500 million a year of financial debt is how I look at it. So I’m not saying that’s a limit, but I’m saying that, that’s certainly what our near-term focus is to get to that $3 a share.
And I guess what I was asking was is there a percentage of cash flow that you’re targeting or something like that at a mid-cycle price? Like how do you come up with that level?
Yes. We look at it more on the breakeven side. So pre-dividend breakeven right now, $30 a barrel. I think that number stays fairly consistent here over the coming years as capital efficiency stays strong, base declines are reduced. And then above that, our large shareholders universally have said they want a base dividend that’s protected below $40 oil. Right now, the base dividend was protected at $35. That will go up over time, but you also might have less shares over time, less debt. So that frees up some more cash to go to the dividend. But overall, cash returns have been widely discussed over the last couple of quarters. And the only thing we have universally heard from large long-owned leases more base dividend sooner. And that’s why Travis is making a commitment to get to three by year-end with Board support, should conditions remain.
Got it. And Travis, very quick question here, but you – I think you mentioned 400 rigs in the Permian in a year or so. We’ve talked here a little bit about Permian takeaway on the gas and NGL side. But what are the other challenges that the basin could face if we do see that kind of growth? And how are you positioned to be ahead of that?
Well, I think if you’re asking what are some of those constraints going to be if you get to 400 and what Diamondback is doing to prepare for that? Well, again, a part of it goes back to the long-standing relationship we have with our service partners. But secondarily, anything that requires boots or tires in the Permian Basin is going to continue to be tight. And that means we’re going to have to attract – as an industry, we’re going to have to attract more workers into the Permian Basin like we did in 2018, 2019. And that’s going to – you’re going to see that translate to an increase in labor costs. But again, those cost increases are going to paint pretty much all of us with the same brush. And we’ll focus, like I tried to highlight earlier, we’ll focus on the variable side, things we can actually do something about. But 400, what do we peak at Danny, out here in the Permian.
Particularly like 490, and we exited pre-pandemic around 400 rigs.
So we’re – even though I think those rigs are a little bit more efficient today than they were then, we’re approaching or will approach by the end of this year sort of where we were at the end of 2019.
Okay. Thanks for the answers guys.
Thanks, Nitin.
Thanks, Nitin.
[Operator Instructions] Your next question is from Leo Mariani of KeyBanc.
Hi guys. I just wanted to ask a question on the potential for FANG to return to a little bit of production growth at some point. You clearly mentioned that here in 2022 with the looming threat of Iranian barrels it was certainly one of the key issues that was keeping you guys away from growing. And also, based on your comments, maybe we’re not quite back to pre-pandemic demand but we’re very close. So as we look into next year, if we are above pre-pandemic demand levels and the Iranian situation has resolved itself one way or the other, could that be the time where maybe we see some modest growth from FANG? And how do you think about what the right level of growth is eventually?
Yes. I don’t know what the right level of growth will be or when it’s going to occur. I can tell you definitively right now, what’s being valued by our investors is a shareholder return program. And no one wants to see that shareholder return program put at risk with volume growth, not for Diamondback specifically for our industry in total. So look, the world will be calling for oil growth at some point in the future. And our industry is going to have to figure out the right way to respond while not putting the shareholder return program at risk. We’ve spent the last decade consuming capital and now we’ve got a little bit of sunshine in us where we can return that capital to our investors that have been waiting patiently and sometimes impatiently for this return. So it’s a good question to ask, Leo, but I can – I can’t give you the time at which Diamondback or the industry is going to respond to growth. But I’ll tell you, when we do, it’s going to be in conjunction with creating unreasonable value for our shareholders.
If we do.
If we do.
Okay. Understood. And I just wanted to ask quickly on the 2022 guidance here. Maybe just starting with the CapEx. It’s a fairly good range, $1.75 billion to $1.9 billion you did describe having a percentage of some of the services locked in for the year here. So just definitely wanted to get your thoughts on kind of what the $150 million variability could be here in 2022? Because it sounds like you’re not going to change the program and there really won’t be production growth. And then just additionally, looking at the production side of the guidance. If my math is right, it looks like you guys either were kind of the very high end of the oil every quarter in 2021 or actually beat it. So as you’re kind of looking at that guide in 2022, should we be thinking that you always have a slight bit of conservatism to allow for things that could go wrong in the field. Just wanted to get a little bit more color on the production and CapEx guide in 2022.
I think we always take a little conservatism for the good guys into our plan. Drilling and completing 280 wells at the – at your AFE number for a year is not an easy task. It might look easy for me in my Excel model but actually doing it in the field is pretty darn impressive. So we certainly want to give some room for guys to do what they do in the field, but also service costs are going up. I mean, Travis mentioned a very high rig count number in the Permian. If that number comes to fruition, there’s going to be pressure on all the variable costs and the fixed cost in this basin. So fortunately, we have the 12 rigs we need. We have the three simul-frac crews we need. This is not a year where we need to go find eight crews – or eight rigs and three crews. We might have to pay them a little more to keep working for us, but that’s the risk for the high end in the back half of the year.
Okay, it’s definitely helpful. Thanks guys.
Thanks, Leo.
Your next question is from Charles Meade of Johnson Rice.
Good morning, Travis and Kaes and the rest of the team there.
Good morning, Charles.
Travis, this goes back to some of your earlier comments about the – really what seems like a linchpin for your strategy, this idea of a mid-cycle oil price, why is $60 the right price?
Yes. We asked that question every day. But one of the things that’s – when I ask that question, one of the responses I got was, what do you think the average price was for the last seven years, and that’s $53 a barrel. It’s really easy to get you fork about $90-plus oil. And in fact, I’ve seen – I think I’m seeing some of that for you in our industry right now, certainly in the commentary that’s out there. But we know geopolitically, there’s dollars that are in today’s oil price that God willing will be resolved without arms conflict. We know that there’s Iranian barrels that are probably coming on, I said, by the end of the year, but it may be at the end of this month. And we’ve got this further in the Permian Basin that’s continuing to lift U.S. production forecast. And while OPEC hasn’t performed up to their 400,000 barrels per day per month production increases, but I think they’re getting closer to it. And I don’t know what their surplus is, but it’s not zero yet. So all of those things, to me, you add them together actually seem to be a little bit more bearish for crude than it does to be optimistic. And the other thing is if we’re wrong and oil price is higher, we’re going to generate a lot of free cash flow, and our investors are going to get a lot of that return to them. And if I’m right, then we’ve protected our investments, and we’ve made the right decisions. So $60, I don’t know that it’s a hard and fast number, but it’s kind of the aperture at which we start all of our decisions on investments, whether it’s M&A or drilling wells or share buybacks.
That’s helpful, Travis. It seems as good as any other number to me. I just wanted to hear more of your thinking. Quick follow-up. I noticed that you guys said you drilled – or I think we’ve drilled and completed a Barnett well in the quarter. Was that on the – I’m guessing that was on the Limelight acreage. And is there any kind of rate of change there that was worth highlighting?
Yes. We drilled a couple of wells there. I think we have a couple of planned this year. It’s still early in the testing phase, but at $90 oil, it certainly competes even at $60 oil, including the low entry cost, it competes on a full cycle basis, but not yet does it compete with our core Midland and Delaware Basin position.
And I think one add is to that is that right now, we’re drilling single wells. And there’s a huge cost inefficiency when you’re drilling single wells trying to delineate a play. Once you move into full cycle development and you can drill at least four wells, simul-frac operations, and combine that with the efficient drilling operations, you can drive a lot of cost out of the equation, which raises the economics on a play like Limelight and actually makes us start to compete for our capital with the other items in our portfolio.
Got it. Thanks for the detail guys.
Thank you, Charles.
I will now turn it back over to Travis Stice, CEO, for closing remarks.
Thank you again to everyone listening today. If you’ve got any questions, just reach out to us using the contact information provided.
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