Diamondback Energy, Inc. (FANG) Q1 2022 Earnings Report, Transcript and Summary

Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 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 call 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. Please go ahead.

Thank you, Amanda. Good morning, and welcome to Diamondback Energy's First Quarter 2022 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 condition, 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. Reconciliations 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 first quarter earnings call. In February, Russia launched an unprovoked invasion of the sovereign nation of Ukraine. We at Diamondback strongly condemned Russia's actions and aggression. Our thoughts and prayers are with the millions of men, women and children affected by this unjust war. And while we desire a quick and peaceful resolution to this conflict, we recognize that this war could go on for quite some time. We will continue to support the innocent victims of Ukraine just as we did earlier this year, when we announced a $10 million commitment to various non-profit entities providing vital humanitarian support. Russia's actions have plunged the global energy markets into turmoil. As the world and especially our allies in the European Union grapple with the potential loss of a major source of their energy supply and rethink their respective energy policies, this war has magnified the interconnectivity of the global energy equation and the impact post-Cold War globalization has had on all supply chains. It has also reminded the world of the importance of the traditional oil and gas to the global economy as we're witnessing the impact high energy costs can have on the consumer and the economy in real time. As the war in Ukraine and the resulting governmental sanctions continue, Russia's oil production is expected to be impacted by shut-ins, natural declines, storage limitations and lower exports, creating a global shortage of oil. Over the next few years, we will need to make up for this lost production, and we believe that the U.S. oil and gas industry is best suited to provide the low-cost environmentally-friendly barrels needed to ensure global energy supply. However, today, we are operating in a constrained environment with inflationary pressures continuing to increase across all facets of our business. Also labor and materials shortages are now present across the supply chain. We at Diamondback are fortunate to have secured the necessary equipment, personnel and materials to run our 2022 capital program, but increase in activity now would result in capital efficiency degradation that would not meaningfully contribute to fixing the global supply and demand imbalance in the oil market today. Therefore, Diamondback remains committed to maintaining our current oil production levels of approximately 220,000 net barrels of oil per day. While we believe that efficiently growing our production base is achievable over the long term, we do not feel that today is the appropriate time to begin spending dollars that would not equate to additional barrels into multiple quarters from now. We continue to focus on capital efficiency and strive to operate with the highest level of environmental and social responsibility. At Diamondback, we plan to invest approximately $60 million to reduce our direct emissions and lower our carbon intensity, including ending routine flaring by 2025. This figure does not include the hundreds of millions of dollars we expend to electrify our production fields and to build pipelines to ensure we produce and transport fluid with the lowest emission intensity possible. These investments are not only good for the environment, but also smart economic decisions that we expect to lower our operating costs. By investing in infrastructure in our high activity levels, we now have the ability to run a dedicated electric fleet for the foreseeable future. We've partnered with Halliburton to secure our first electric frac fleet, which will run in our Martin County acreage off power generated from the central location and delivered via existing lines, reducing our Scope 1 emissions profile. This partnership will also lower our cost per foot, primarily due to fuel savings, decrease our footprint on location and increase our operational efficiency as a result of lower maintenance and non-productive time. We expect this fleet to be operational in the fourth quarter. In 2021, we also announced initiatives to reduce our Scope 1 greenhouse gas emissions or GHG intensity by at least 50% and reduced methane intensity by at least 70% of from 2019 levels by 2024. In 2021 alone, we reduced our Scope 1 GHG and methane intensities by 15% and 21%, respectively, from the 2020 levels. Lastly, we launched our Net Zero Now strategy under which, as of January 1, 2021, every hydrocarbon produced by Diamondback is anticipated to have zero net Scope 1 GHG emissions as we offset these emissions with certified carbon credits. Moving to first quarter performance. Our production of 223,000 barrels of oil exceeded the high end of our guidance range, creating $1.4 billion in operating cash flow. We were able to keep our capital costs in check, spending $437 million in CapEx during the quarter, nearly hitting the low end of our guidance range of $435 million to $475 million, and pushing our free cash flow for the quarter to $974 million. We returned $555 million of cash back to our stockholders or $3.09 per share representing 57% of Q1 2022 free cash flow and 50% of adjusted free cash flow, which we calculated by adding back the $135 million in cash we used to terminate certain future hedge positions. This return was made up of stock repurchases, the base dividend in our first variable dividend. As we've said in the past, our share repurchase program is opportunistic, and we stuck with our plan of evaluating our share repurchases just as we would with any acquisition. A buyback must generate a return well in excess of our weighted average cost of capital, assuming a reasonable mid-cycle oil price. In the first quarter, our price debt was approximately $60 a barrel, and as such, we were able to take advantage of some of the volatility in the new market and repurchased 57,000 shares at an average price of $117 a share. Through the end of the first quarter, we've spent about $440 million or 22% of the $2 billion program our Board authorized last September. Additionally, we once again increased our growing base dividend, which we view as our primary, constant and predictable form of shareholder returns. It's now at $2.80 a share on an annualized basis, up 17% quarter-over-quarter and approaching our target of $3 a share. We have now increased our base dividend by a quarterly CAGR of over 11% since it was initiated in 2018. Today, this represents a current yield of just over 2%. Finally, with the free cash flow returns through our base dividend and repurchase program does not equal at least 50% of our free cash flow for that particular quarter, and we've committed to make our investors whole 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. For our strategy, we allocated $422 million to our first variable dividend this quarter or $2.35 per share, putting our total dividend payout in the first quarter at $3.05 per share or nearly a 10% total dividend yield. We met our commitment to return at least 50% of free cash flow to our stockholders and use the remaining cash to strengthen our financial and operating position. In the quarter, we fully redeemed $500 million of notes due in 2024 and $1 billion of notes due in 2025. We also took advantage of the flat long end of the curve by pricing $750 million in new 30-year senior notes at 4.25%. This liability management exercise reduced our absolute debt by $750 million, decreased annual interest expense by $20 million, pushed out the average weighted maturity of our debt profile by 5 years and kept our average weighted cost of debt flat. With only one tranche of near-term maturities outstanding, we are pleased with the progress we've made to improve our investment-grade balance sheet and are nearing our leverage target of approximately 1x at $50 oil which would equate to approximately $3.5 billion in absolute debt at the parent level. We also continue to put our cash to work by high grading our existing inventory position through small bolt-on acquisitions. And we are excited about blocking up our reward position with the acquisition we completed in January. This bolt-on added approximately 6,000 net acres in Ward County and gave us an additional 60 long lateral locations with an 85% net revenue interest in a high rate of return area. In fact, we've already begun drilling the position, but do not expect to have production until late this year. As we look to our outlook for the rest of 2022, our simple plan has not changed. Maintained oil production of approximately 220,000 barrels of oil per day by spending between $1.75 billion and $1.9 billion. At the current strip pricing, this production and capital spend equates to approximately 400 -- $4.5 billion of free cash flow, which per our returns framework, gives us a minimum of $2.25 billion of cash back to our investors. We're off to a good start for the year, mitigating inflationary pressures while justifying our social and environmental license to operate. We believe our capital discipline and returns profile is still the best near-term path to equity value creation, while our operational execution provides differentiated returns to our shareholders. With these comments now complete, operator, please open the line for questions.

[Operator Instructions]. Our first question comes from the line of Neal Dingmann from Truist Securities.

Travis, first question really, the obvious just on shareholder return and odds. Specifically -- well, I guess maybe tackling it a little bit different. I'm just wondering what levers would you all think about pulling if oil were to go potentially in a super spike scenario, where if Russia oil would decouple or if oil completely goes the other way and rolls, assuming something happens to Putin. So I'm really just trying to get a sense of what sort of quarterly changes you would or would not make if this were to happen down the line.

Well, certainly, from a quarterly perspective, from an operational perspective, we're pretty set on this year's plan. And we have the ability, obviously, to ratchet things down, but as I tried to lay out in our prepared remarks, ratcheting things up right now is not really the right answer. If you're asking a question specifically about buybacks, Neal, we're going to stay disciplined in our approach to buying our stock back. When we look at mid-teens returns or mid-cycle pricing, that's really not changing. I think what matters most though, Neal, is that we're returning cash to shareholders, and we're giving our shareholders the flexibility to do with that cash as they see fit. That's kind of how I view the world right now, Neal.

No, I like that flexibility. I think it makes a lot of sense as I think investors do. Then my second question just on your capital guidance, specifically looking at the $150 million of inflation, the $125 DUC benefit and then the $60 midstream incremental moves that you talked about since '21, really just wondering, is there a potential for each of these to move further this year? And then does this sort of '22 spend set you up for a stable '23 production?

Yes, Neal, I don't see any changes. I mean I think we're seeing inflationary pressures across the value chain. Fortunately, we baked a lot of that into our guidance for the year. And fortunately, we had a strong Q1, which if you annualize Q1, you'd be towards the low end of the range. So it gives us a little flexibility in the back half of the year. And second to that, I think we're debating internally what does 2023 and beyond look like. We're not ready to give an answer to that today. But it doesn't mean that the plan is zero growth forever. I think we have the flexibility to ramp up a little bit if we needed to, if that was the decision come kind of late summer for 2023 and beyond.

Our next question comes from the line of Arun Jayaram from JPMorgan.

Arun, are you on mute?

Yes, I'm sorry. I didn't hear my name. Sorry about that. Travis, I want to get your thoughts. Obviously, looking at the near-term performance of the stock, you've clearly lagged your oil beta as well as our sense of execution, which has been good in the field. So I was wondering if you and/or Kaes could talk a little bit about the bear thesis on the stock. As you know, there's a number of properties on the market in the Permian and the market appears to be concerned about Diamondback executing perhaps a procyclical type of M&A deal in this type of environment as the buyback pace has waned a bit. So I was wondering if you could maybe talk about that and just your broader thoughts on M&A in this kind of $100-plus oil environment.

Arun, if I could control the price of stock, it would be a lot higher than it is today, granted. But I can't. But what we can control is how we allocate capital, how we execute in the field, how we can generate more cash per barrels than anyone else. Those are the things that we really can control. It is -- we do hear a lot about this narrative that Diamondback is a serial acquirer, and let me just put it simply. Large-scale M&A today is quite frankly, off the table. We've got nothing on our deal sheet that's considered more than a tuck-in like the one just announced in my prepared remarks. This remains a seller's market, and we're not going to underwrite M&A at today's oil prices, just like we're not going to underwrite repurchasing stocks at today's oil prices. So I hope that's clear in both of those 2 points that I made, Arun.

Great, great. So it sounds like large-scale M&A is off the table today, if I -- based on those comments.

Yes. Let me reiterate that. Large-scale M&A is off the table. I'll reiterate that point.

Okay. Yes. That's clear. The second point I wanted to make is just looking at the cash flow statement for calendar 2022, on our model which is a bit below the strip call it, $6.2 billion, $6.4 billion of CFO, a little under $1.9 million of CapEx. If we go through all of the uses of cash including nearly $800 million of debt reduction year-to-date, we'd still get 1 -- over $1.2 billion of cash build this year. So I was wondering if you could talk about some of the priorities for this excess cash. I think you highlighted maybe a debt target for FANG, stand-alone at $3.5 billion. But I was wondering maybe you could talk about uses of cash if this high commodity price environment continues.

Yes. Arun, good question. I wouldn't say $3.5 billion is a hard and fast number before we ramp up shareholder returns, but certainly would like to take advantage of this market by taking out our 2026 notes and, therefore, not having any near-term maturities before 2029, which opens up the door for accelerated cash returns. I think that's going to happen sooner rather than later. Just generally, we do want to keep a cash balance, but we're not going to sit on a large cash balance, and we think no debt isn't the right answer. So we're not going to sit on it. And therefore, we're going to return it. This is an active discussion we have with our Board every quarter on cash returns. And I think generally, we're going to be supportive of more cash returns as the balance sheet is put in fortress shape.

Our next question is from the line of Nitin Kumar from Wells Fargo.

I want to start with Permian takeaway on the gas side has been a topic of discussion over the last 3 months or so. Just want to see what you guys are seeing on the ground and maybe if you could talk a little bit about your low assurance into '23 and '24?

Yes. Nitin, I think people are -- on the midstream and the upstream side, are coming together to solve this problem. And you've seen a couple of announcements on expansions of a couple of existing pipes in the last couple of weeks. We still think there needs to be a large pipe built, new-build pipe, which hopefully happens here in the next month or 2 from an announcement perspective. And generally, going back to what we said last quarter, we have -- we don't have take-in-kind rights for all of our gas, but we do have full assurance for all of our gas. So we are exposed to Waha. We've hedged much of our exposure in 2023. And we think that's the tight spot. And the gas is going to move. It's just a matter of price. And I think there's a lot of constraints on Permian growth right now as we've seen anecdotes from others on trying to ramp activity into this constrained environment. So generally, I think the gas thing gets solved. I think both sides are as incentivized as ever to build the pipes and that should clear the way for Permian growth in the out years.

Great. As my follow-up, inflation did not feature as prominently in your release as it did for others, but you did talk about constraints. Kaes, you also mentioned possibly looking for growth. Are there any specific areas as we look into 2023 that are tighter on the supply chain side? And maybe talk a little bit about how you're contracting for those services right now.

Yes. I would say right now, everything is tight across the board, whether it's sand, casing, new high-spec rigs, frac crews; everything is very, very tight. We're doing our part by keeping our activity levels flat. We're running the 12 rigs we need and we're running the 3 simul-frac tractors we need with a fourth spot crew. But hearing anecdotes of not being able to get casing, not being able to get sand, these are things that we've done our best to secure, and I think we're in a really good position. And it kind of ties to what Travis was saying, is if you're going to bet on someone in an inflationary environment, it's Diamondback. I mean we control costs as well as anybody in this business, and that's what we're laser-focused on in 2022.

Our next question is from the line of Scott Hanold from RBC Capital Markets.

If I could kind of flash back to the shareholder returns kind of strategy here, and I think you guys have been pretty articulate in how you think of a big picture. But -- and Travis, I know you made a point of one -- ones here earlier in this call about does it make sense to buy back Diamondback stock at this point in time. So when we think about how you return that cash going forward, should we anticipate at kind of heightened oil price levels, you are going to stick to say, that $60 mid-cycle price and the large quantum of return likely is going to be in a variable dividend? Is that how we should think about it until there's a more material pullback in sort of the equities here?

Yes. I think that's a reasonable approach. But Scott, I also think you have to be cognizant of what our industry has done over the last 10 years in respect to share repurchases. We've typically, as an industry, chased the oil price and repurchased shares back all the way to the top. We're trying to be mindful of that and disciplined in our approach. And I've tried to be as articulate as I could about the way that we think about share repurchases as any other form of capital allocation with that mid-cycle oil price. Mid-cycle oil price isn't -- [it's like] oil price, it doesn't change. Now what could change is that as we continue to accumulate cash, that's going to have an influence on our future capital allocation, both in the form of share repurchases and increased variable payouts.

Yes. I wouldn't say we haven't had opportunities. I mean we've had opportunities even in Q2 to repurchase shares given the volatility in this space. So there's enough volatility out there to give us opportunities. And I would say the share repurchase is more defensive than offensive. And when things are going really, really well like they did in the first quarter, we make up the difference with the variable dividend.

Got it. Appreciate that. And on the first quarter results, what to me stood out was your oil price realizations were extremely strong. Can you talk about the dynamics specifically in the quarter and if that's continuing at this point in time? It looked like you all got average premium to WTI pricing.

Yes. I would say it was more one-off than anything, but the volatility in Brent and Dated Brent, in particular, versus WTI benefited us. I'd say about 30% of our oil production received a Dated Brent price for barrels going to Europe, and that was in our favor there in Q1. So I think generally, we've always guided to 95% of WTI as our realization. That might need to move up a little bit, particularly with WTI going up as much as it has, but it's going to be tough to hit 100 consistently.

Our next question is from David Deckelbaum from Cowen.

Thanks, Travis and Kaes and Danny, thanks for squeezing me in. Travis, I wanted to just follow up on your comments that you made around capital efficiency degradation for deploying capital in today's environment. I guess how do you think about those conditions resulting in improved capital efficiency over time? I guess it sounds like the variables are that -- there really just isn't very much availability of equipment, significant delays. I know that you guys are benefiting from having prepurchased a lot of -- some of the raw materials for this year's program. But I guess, are we to think about -- when you talk specifically around capital efficiency, if you stood up a rig today, that the free cash payback period on that would be significantly longer than the year?

Yes, I think there's 2 points. Your first one is correct that capital efficiency does imply that the payout for that investment is much longer, notwithstanding the fact that the production from that, the way we develop these assets with multi-well pads is quarters away. The second thing is, is that in the hyperinflationary environment like we are in the Permian right now, standing up the rig using your example really means that we're, in most instances, we're going to be taking that rig away from somebody else. So -- and that applies to really all services. And -- so if you're looking to increase the total barrel production out of the Permian, you just really need to be reallocating, so it's not really helping the global supply/demand equation because that's really how tight the services are out here today.

Yes, it was more a macro comment that the service market is a zero-sum game right now and us stepping on the accelerator would result in someone else not. And so we want to maintain that capital efficiency that we have and the trust that we've earned with investors that this is the plan.

We've seen in the past in these hyper inflationary environments that supply chains ultimately normalize. But it takes time for that normalization to occur, which is measured in quarters, if not years for it to normalize. And when it does, then you start to have a greater opportunity to grow without degrading your capital efficiency.

I appreciate the responses, Travis. The last one for me is just on the Ward County acquisition, it sounds like you guys are already drilling some of those locations there. I guess when you're making a -- when you're making an acquisition right now, I know you said large scale is off the table. But are these smaller deals -- should we think about these locations moving to the front of your program?

Yes. These were some pretty high-returning locations mainly because the acreage has an 84% NRI. So an extra 9% NRI was about 1/3 of the deal value. And so that makes a completely undeveloped unit in the Delaware basin very competitive with Midland Basin unit. So I'd say this deal is the exception versus the norm. It was agreed to about 6 months ago. But if other opportunities like that come about, I think it's a good use of cash as long as we're not impacting our cash return program.

Our next question is from Derrick Whitfield from Stifel.

Congrats on your quarter-end update. Following up on David's first question, could you broadly outline the macro and investor conditions that would support a decision to pursue growth over 5% per annum?

I think what you're asking us to do is start forecasting 2023 growth rates that we're not really ready to talk about 2023. I think though, Derrick, if you look at the macro uncertainties that are still out there, let me try to enumerate some of those. You've still got Iranian barrels, whether they're going to find a way in the market. You've got Venezuela, you've got Libya, you've got continued a little bit of surplus capacity in the OPEC+. Those are all volumes that can come on to the equation of the supply-demand equation. You've also got the continued demand impacts of COVID, particularly in the Asian markets right now. And then lastly, to say bluntly, the administration's comments are certainly causing a lot of uncertainty in the market, both in the terms of regulatory taxation, legislation and negative rhetoric towards our industry. And that creates uncertainty in our owners', our shareholders' minds about what the future of this industry really is. And so I think this represents on that front, a pretty unique time to have a sober assessment of what an energy policy really needs to look like for the United States, one that recognizes all forms of energy, while at the same time, having aspirational goals about a more sustainable future.

Thanks, Travis. I certainly appreciate those comments and understand those. As my second question, I wanted to follow up on gas egress and more specifically, your view on how you'd like to position Diamondback in the value chain for LNG offtake. With the understanding that you are an oil company at the core, have you evaluated or would you consider direct offtake contracts with European utilities to better position Diamondback for higher realizations?

I think we consider it, Derrick, we just want to have control of enough molecules to do anything meaningful. This goes back to the take-in-kind rights, right? We sell -- we exchange to the custody of the molecule at the wellhead outside of 200 million a day we have on the Whistler pipeline going down to Katy in South Texas. So we really don't have control over a lot of gas. The company's grown through acquisitions. A Lot of times, the gas came dedicated already with no take-in-kind rights for that operator.

Our next question is from the line of Scott Gruber with Citigroup.

I guess just listening to the conversation here this morning you guys mentioned the e-frac coming in during 4Q and how that will help efficiency. And there's obviously been various drilling optimization software that has been developed to help trim those drill times. Is there an ability for Diamondback to grow volumes modestly without adding an additional rig or 2 and more frac time? Or is that just not possible?

I think it's certainly possible, Scott, and certainly it's part of our assessment of where we're headed and also ties into this mantra of capital efficient growth or capital efficient maintenance. It's amazing what the organization has done in terms of efficiencies. Three simul-frac fleets have doubled our efficiency on the frac side. And on the drilling side, like you mentioned, the clear fluid drilling system as well as moving on to electrification has reduced costs and cycle times. So I certainly think it's possible, and we continue to see improvements throughout this year and certainly going into our calculus for what does the next few years look like.

And Scott, when you think about the improvements that Kaes just talked about that are operationally and execution focused, those are made irrespective of commodity price or service costs. And what's exciting about those and what I'm so proud of our organization about is those are permanent. Those are permanent savings that go forward. And when you start doing the relative game to Diamondback versus others' performance, that's what creates the spread. And this is not just a recent phenomenon. Our organization, their stock and trade has been these types of incremental improvements year-over-year regardless of the economic or commodity price backdrop. And I think it's fair that we're going to continue to do that. It gets harder in times like today, but it doesn't mean that we still can't find differential ways to do more with less. And the second point is that as we fully embrace the Northern Midland Basin with the assets that we acquired through Guidon and QEP coming on the production mix back half of this year and fully into 2023. Those wells are so good, you will see a natural uptick in capital efficiency because we -- those wells deliver more per dollar spent.

Got you. Yes. I guess that was the kind of heart of my question is, is there enough kind of incremental gain on the kind of process efficiency coupled with the Martin County program hitting its full stride? Is there enough combination there that you can actually achieve, call it, 5% growth without adding an additional rig?

We'll see. It's still early. So we'll see. I think we're really focused on getting through the rest of this year in a very tight inflationary environment.

Next question is from the line of Jeoffrey Lambujon from Tudor, Pickering.

My first one is just a follow-up on some of the cost commentary from earlier, if you wouldn't mind sharing some additional insight that you've got just given your history in the basin. But with your outlook for well cost per foot for the year, in particular staying consistent with the initial guide even as other operators are talking up quarter-to-quarter changes with uncertainty beyond that as you go through the year, I just wanted to ask about what you are doing in the field to mitigate higher costs you might be experiencing or just plans to -- for activity in the field to mitigate expected costs in the future just in terms of flexibility around who you contract with for services while still maintaining and upholding the low-cost operations that Diamondback's known for?

Yes. Good question, Jeff. I mean we've obviously baked in some inflation into these costs and went into the year at a lower well cost when we went into 2021 and even in the face of an inflationary environment last year. But generally, there are service providers pushing price. And sometimes we decide not to keep working with those particular service providers. So I think our ability to control costs is because we control a lot of the process with our business partners on the service side. We recognize they need to make margin. But if there is another provider that can provide the same service for less cost, we'll go that route. And we've done that a few times this year. So that's helped us control things a little bit.

And Jeff, those are true strategic comments that Kaes just made. But look, tactically, what we continue to see is our operations organization getting the TD faster on a quarterly basis. And that kind of goes back to the comments I made earlier. This is what we do. So getting the TD faster translates to cost savings that become permanent. Also completing more lateral feet per day as an efficiency gain this year is another one of those tactical things that we're doing that's helping us hold the line on an increasing cost backdrop. So -- and just to emphasize, we always get the question asked, what is it that makes the secret sauce of Diamondback in our low-cost operations as you just pointed out. And it's really not 1 or 2 things. It's really a consistent laser focus on every single decision that we make that spends dollars. And the cumulative effect of that laser-like focus allows Diamondback just not on a quarterly basis, but now almost for a 10-year time period, maintain the lowest cost operations and the best execution out in the Permian.

Perfect. I appreciate the detail and the reminders. My second one is just on the balance sheet, really just around what you see what's left on the opportunity for further strengthening from here. I know you all talked about and flagged that 2026 is in the past and spoke to debt targets that can also be flexible. But it seems like you are within striking distance here of an optimal balance sheet position for the medium to long term. So just wanted to get your latest thoughts on that given the progress you've made so far, especially recently. And I apologize if I missed this earlier.

No. Listen, I think we feel fine with everything we have due 2029 or later sitting out there. And if we take care of the 2026 is, which should be in a matter of months, not years, we'll be in a position to have discussions about increasing shareholder returns beyond what we're already doing.

Our next question is from Nicholas Pope from Seaport Research.

First, I wanted to commend you guys on that ESG kind of real-time data that you are providing because I think it's probably one of the best in the sector. But you provide the data, so I've got a question about it a little bit. You kind of talked about kind of gross gas flared. And I saw in 1Q, it kind of creeped up from kind of where it was in fourth quarter, where it was in the first quarter of last year as kind of a percent of total like gross gas production. So I was curious, like is it -- what drives that? Is there some seasonality in that? Is it -- I mean, is it limited capacity to move gas? I mean I'm just trying to understand a little bit about kind of the movement in that metric, which is a big part of kind of the CO2 emissions, I think that you all report.

Sure, Nick. Two things. The first comment on disclosure, I appreciate you saying that. Our Board has mandated us to not only be best-in-class on actual performance, but also best-in-class in disclosure. And there's a lot of our organization that is focused on delivering these results, and we're proud to report them. And I think if those who haven't had a chance that are on the call to look at the ESG detail in our investor deck, which is up on our website, I strongly encourage you to do that. The second part of your question, Nick, was gross gas. And that's -- the reason we reported that is because that's a way that you can back calculate and verify our numbers, but that has to do with the acquired volumes. Kaes?

No, it's all due to plant turnarounds, right? I mean we put out a slide that explains that 75% to 80% of our flaring is due to downstream issues. And we're trying to push and incentivize our business partners on the midstream side to do better in terms of flaring, sometimes through contracts where we pay them more per Mcf, if take pay less than 1%. But really, timing-wise, Q1, a lot of turnarounds from some of our business partners on the midstream side. There is some seasonality to it, but that's why we push them for more interconnectivity among their peers, so that if their plant goes down, they can send it to another plant or to a peer and we'll still pay them. So part of the whole value chain is we need our friends on the G&T side to work with us here.

And Nick, we view that as a win-win or a lose-lose. So we're not trying to position ourselves as a win versus lose on the G&T side. We know that emissions from the product we produce need to be eliminated and minimized as quickly as we can. And that's the reason that we spend time in conversations like this talking about our G&T business partners as well as including some slides in the ESG detailed part of the deck that highlights what Diamondback was responsible for and what our midstream guys were responsible for both planned and unplanned outages.

Got it. That's actually very helpful. I appreciate it. And kind of further on to the kind of the other components of this, you kind of talked about the electrification of compression of parts of the frac fleets. Is that something that -- is that going to be showing up as part of the LOE kind of improvements that you're working on? Is that where it shows up? Or is it primarily going to be something that is reflected in these ESG metrics when you think about that move towards the electrification of a lot of assets?

Well, electrification in the field helps LOE. So electrifying all of our fields is not only environmentally friendly, but also cost friendly, getting rid of infield power generation. But on the frac side and the drilling rig side, moving rigs and frac fleets to electrification would help lower costs on the capital side, but also then lower our combustion percentage of Scope 1 emissions.

Our next question is from Doug Leggate from Bank of America.

I guess places and cues are directly correlated with the commentary around your variable dividend. Thanks for getting me on this morning. It's good to talk to you, Travis. Travis, I got to hit this right up-front. Look, if you -- how can you say you think your stock is undervalued, but you're not prepared to buy it? Variable dividends take cash off the balance sheet. They don't get capitalized in the business, which is a finite inventory. How do you expect the market to pay you for a variable dividend? Just, to me, in this business, it doesn't make a lot of sense. I'd just love your perspective.

Yes, Doug, listen, we've tried to outline exactly our thoughts on the rationale behind all of those things. My comments on the stock price is really a function of what I can control and not control, and I can't control the actual market, what the stock is -- what the actual stock price is. We try to be very disciplined and we are very disciplined in the calculus we use to buy anything, whether it's our stock, whether it's acquisitions or whether it's making drill well decisions. And I've tried to outline the mid-cycle oil price of $60 a barrel. I think that could change as we continue to accumulate free cash. Mid-stock oil price won't change, but our ability to buy more shares back will change, but we made a commitment to distribute at least 50% of our free cash flow and other than [ordinate] on the balance sheet, which we said we're not going to do, we're going to hard that commitment and return at least 50%.

Yes. I understand completely the rationale. It's an intellectual debate, perhaps, but equity volatility correlates with balance sheet structure. So EOG, Pioneer, some of your other peers are choosing to have net debt zero. So we'll carry on the debate. I want to ask about the -- a more specific question to the current commodity environment and how it's impacting your cash flow outlook, specifically, cash taxes, so this might be for Kaes. We've got a much higher gas price, obviously. We've got a backwardated curve, obviously. I assume that's accelerating the inflection in when you get to a full cash tax position. So if you can just give us an idea what you see happening in that regard? And I'll leave it there.

Yes. Good question, Doug. We raised our cash tax percentage this quarter because we weren't running $100 oil in our initial guidance in February. There's still some protection this year. We do have about $1.5 billion of NOLs that will protect us next year. So we won't be a full cash taxpayer next year in '2023. Some were NOLs that got pushed out, couldn't use it this year, so we've got to use it next year. And then commodity prices stay where they are. Full cash taxpayer by 2024.

So just to be clear, even with the forward curve case, you're still good through the end of next year?

Yes. I mean partially, right? I think our protection will decrease next year, but there will be some protection and then full cash tax payer in 2024.

Our next question is from Leo Mariani from KeyBanc.

I just wanted to follow up a little bit on some of the inflation commentary here. Just wanted to kind of clarify sort of what I heard. It sounds like you'll have all your equipment here for your 2022 program. But just wanted to get a sense if generally, the prices for the big ticket items on the service side are locked in for 2022? Or perhaps could you see, I'll just call it some inflationary risk in the CapEx maybe in the second half? And then as we look to 2023, is that where you think that inflation could be maybe a larger problem if commodity prices are well bid later this year?

Yes. I mean, it really depends, right? I mean it depends on what happens in the situation with Russia and Ukraine as it relates to pipe costs, right? We thought pipe costs were going to come down in the back half of the year. It doesn't look like that's going to happen this year. It might happen next year. I mean I think there's a little push/pull, Leo, with this business tends to sort out supply chain issues over time. And as commodity prices stay stronger for longer, some of the tightness will get sorted out. So certainly, I'm not going to make a prediction that 2023 inflation is going to be as much as 2022, but we're certainly seeing inflationary pressures across all the big ticket items right now. And some of that pricing for the big ticket items is incentivizing new builds, which tends to lower prices. So I think there's a little bit of push/pull. Jury's still out on 2023.

Look, we will be affected by inflation, no 2 ways about it. But the bet that we've always made here internally is that we will be affected the least of anyone else because of our efficient operations. And you see it in the first quarter of this year, we were all affected by the same inflation, and we were at the low end of our CapEx guide for the quarter. Recognizing that's going to be a challenge to continue that performance, I still bet on our organization to deliver.

Okay. That's helpful. And certainly, I can see that from where you came out in 1Q on CapEx. And it looks like on the second quarter CapEx guidance, you seem equally confident that you can kind of keep the costs under control. So is this something that could maybe creep up more in the second half this year? Or do you kind of have rigs and crews and pipe locked in here in '22?

I think we feel really good about the budget. Obviously, we're on pace for the low end. I think that's going to be tough, but we feel really good about this year's budget.

[Operator Instructions] Our next question comes from Paul Cheng from Scotiabank.

Two questions, please. I think first is for Kaes. In the cash tax, I just want to confirm in the accounting that you guys have done. You will estimate for the full year what is the cash tax rate and then you apply the same tax rate in each quarter roughly, flat on that and not necessarily based on saying that later in the year that you may have already used some more on the NOL so you will have a higher cash tax. And also then, if we assume, let's say, call it an average $100 WTI price for next year, I assume the cash tax rate would be higher. Any rough guidance that you can give? That's the first question.

Yes, I'll take the second part first. Certainly, the cash tax guidance would be higher next year if we have these commodity prices. I think it's basically pretty close to a full cash taxpayer outside of $1.8 billion of protection. And then second, I think your question related to when does the cash exit the system for cash taxes. And we'll be making payments, our first payment in June for the first half of the year and then quarterly thereafter now that we're heading to cash tax land.

And yes. So is the cash tax rate, say, for the year would be about the same or that they still have quite a fluctuation?

No, there's no fluctuation. So our burden in Q2 is expected to be higher than our burden was in Q1. It's just that the cash is going to leave the system in Q2.

I see. Okay. And the second question is that for this year, it looks like from equipment availability and also a lot in the service price, you guys already done quite a lot. For next year, any kind of rough percentage you can provide how much of your service for CapEx or equipment that you already locked in with a debt price or that is 100% subject to the market conditions at this point?

I would say most of it is subject to market conditions. We did -- we talked about the e-fleet, we signed a deal with Halliburton. That price is fixed and our sand price is fixed. So the rest is going to fluctuate, and we'll see where the market goes over the next few months.

At this time, I'd like to turn the call back over to Travis Stice, CEO, for closing remarks.

Thank you again to everyone participating in today's call. If you've got any questions, please reach out to us using the contact information provided.

This concludes today's conference call. Thank you for participating. You may now disconnect.