Diamondback Energy Inc (FANG) 2021 Q2 法說會逐字稿

Good day, and thank you for standing by. Welcome to the Diamondback Energy Second Quarter 2021 Earnings Conference Call. (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. Please go ahead.

Thank you, Chelsea. Good morning, and welcome to Diamondback Energy's Second 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, CEO; Kaes Van’t Hof, CFO; and Danny Wesson, EVP of Operations.

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. The 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 Second Quarter Earnings Call. Diamondback had an outstanding second quarter, extending its track record of operational excellence. I am proud of everything our team has been able to accomplish this year by pushing the boundaries of our current thought processes and embracing new technologies and playbooks, many of which have come from the personnel we've added through our acquisitions. Nowhere is that more evident than on the drilling and completion sides of the business where we continue to lower costs and improve cycle times. We've decreased our drill times from spud to total depth by over 30% and are averaging just over 10 days to drill a 2-mile well in the Permian -- in the Midland Basin.

On the completion side, we're now running 3 simul frac crews, which lower our downtime and improve our pad efficiencies. We are currently completing approximately 2,800 lateral feet per day in the Midland Basin, an improvement of nearly 70% as compared to our early zipper frac designs. All of these operational advances translate to our ability to do more with less.

While we are seeing some inflation on diesel, steel and other materials, our ability to continually improve operationally and become more efficient has more than offset these cost increases, and our leading-edge DC&E costs continue to be at the low end of our guidance range. As a result, we are decreasing the number of rigs and crews we need to execute this year's capital plan and are reducing our full year capital guidance by $100 million or down 6% from prior expectations.

On the production side, our wells have outperformed expectations this year. As a result, we are slightly increasing our Permian oil production guidance, which should not be taken as a conscious decision to grow. As we look at supply and demand fundamentals, oil supply is still purposely being withheld from the market, and we continue to believe there's not a call on U.S. shale production growth. We will continue, therefore, to target flat oil production for the foreseeable future and plan to do that by completing less wells than originally planned this year.

These operational highlights, coupled with a supportive macro backdrop, led to record free cash flow generation for Diamondback. During the second quarter, we generated $578 million in free cash flow or $3.18 per diluted share. To put this into perspective, we entered 2021 anticipating roughly this amount of free cash flow for the full year. We've already put this cash to work by calling and paying down over $600 million of callable debt so far this year with over $600 million more expected later this year when our 2023 notes become callable. In total, this debt reduction will reduce cash interest expense by almost $40 million annually.

We continue to emphasize that reducing debt and increasing shareholder returns are not mutually exclusive, and we proved this point again by increasing our quarterly dividend by 12.5% from $0.40 a share to $0.45 a share, or $1.80 annualized. This puts our year-to-date dividend growth at 20% above 2020 levels.

At Diamondback, we prefer to talk about our current performance rather than future promises. However, our performance has allowed us to accelerate our debt pay down and increase our base dividend. And we now feel it's appropriate to put up some goalposts as it relates to additional return of capital in 2022, given the current free cash flow outlook and strip pricing.

Our plan is to distribute 50% of our free cash flow to our shareholders in 2022. This form of additional capital return will be decided by the Board at the appropriate time, but we intend to be flexible based on which opportunities we believe present the best return to our stockholders, the owners of our company. Remember, our strategy is unchanged since 2018 when we initiated our base dividend. This additional clarity is simply a evolution of our guidance and also reflective of the maturation of our business. A lot can happen now -- between now and the end of the year, but we feel we are well positioned to take advantage of the current commodity price environment and deliver differential free cash flow in 2022.

Our capital efficiency improvement allows us to maintain an elevated base level of Permian oil production through 2022 by spending approximately $1.7 billion to $1.8 billion of total capital. The continued improvement in our realized pricing and our low cash cost structure combined to form a best-in-class cash margin, which we plan to protect as we layer on hedges that are focused on protecting extreme downside, allowing our shareholders to participate in commodity price upside.

Turning to ESG. We continue to make progress on our ESG initiatives. Flaring continues to be one of the biggest drivers of our CO2 emissions. And while we've made significant progress since 2019, we still have work to do. Our target in 2021 is to flare less than 1% of gross gas produced. And in the first half of the year, we were above that number. Now this is primarily due to the integration of the QEP assets, and we expect this metric to improve as we build out additional infrastructure in the Midland Basin and close the Williston divestiture later this quarter.

We have also begun 2 pilot projects utilizing tankless and limited tank facility designs. While the first tankless facility is expected to be installed in the fourth quarter, we've already had 2 successful limited tank design pilots. On average, this design reduced our CO2 emissions from our storage tanks by more than 90%. Because of this success, we've elected to extend this pilot to another 5 facilities in the back half of this year and expand to an additional 15 facilities in 2022.

Lastly, we are continuing to build out our electrical substations, which will help minimize emissions from combustion equipment, primarily generators and gas engine-driven compressors. We are working to remove or replace over 200 of these units by 2023. The combination of these efforts position us well to meet our commitment of reducing our Scope 1 GHG intensity by at least 50% and reduce our methane intensity by at least 70% as compared to 2019 figures by 2024.

The second quarter exceeded our expectations and exemplified why Diamondback is a leader in the industry. Our people continue to innovate, making us more environmentally responsible and efficient, uniquely positioning us for the future. Our record free cash flow generation allowed us to accelerate our debt pay down and increase our dividend, all the while positioning us for robust shareholder returns next year. We are delivering on our exploit and return strategy, continuing to focus on maintaining Permian oil volumes, reducing debt and returning cash to shareholders.

With these comments now complete, operator, please open the line for questions.

(Operator Instructions) Your first question comes from the line of Arun Jayaram with JPMorgan.

Travis, I want to start a little bit maybe away from the print, but to get a little bit of your thoughts on kind of the A&D market. We sensed a bit of a fear factor regarding your stock and the potential for Diamondback to engage in larger scale M&A with some of the larger packages apparently on the block. So I just wondered maybe you could start and maybe remind investors on your approach to A&D and how you kind of balance, call it, the general scarcity of Tier 1 opportunities in the A&D market versus just economics and returns?

Sure, Arun. A lot of questions contained in there. But just generally, it feels like a seller's market out there. Our M&A focus is really intense around selling noncore assets. And look, one of the most important jobs that we have as management is allocating capital. And when you look at kind of mid-cycle oil price, and we kind of use 50 -- $15 for NGLs and $2 for gas, the NAV of our stock price is much higher than where we are today.

So if that backdrop persists, best use of our capital is not in the M&A market, it's rather in the in the buy back our own stock. But look, we've been very clear what forms -- what our decision framework and our acquisition frameworks look like, and we've articulated that in every earnings call. But today, just doesn't feel like that's the right thing to do. So our focus is simply around monetizing noncore assets and really looking hard at our business. I really like the way our forward plan looks with our existing inventory.

Great. And just my follow-up. You did raise your production guidance for the back half of the year relative to consensus and kind of our model, even if you back out the Bakken. I was wondering, Travis and team, if you could comment on what drove that? And just general, your expectations around 2022. It sounds like we're -- it's a, call it, $1.8 billion to hold, call it, 220 flat next year, but I wanted to get your sense around your second half outlook and thoughts around 2022?

Yes, Arun, I'll take this year first. We are going to close the Bakken a little bit later than we expected due to external approvals. And so therefore, we kind of raised our full year guide by about 2,500 barrels a day, which is 2 months of the Bakken contribution. But above that, we also raised our overall guide for the year up 2%, and that's really on an apples-to-apples basis versus our Q1 guide. And really, I think the impetus for that is some Permian outperformance early in the year. And therefore, I think we're comfortable raising our Permian guidance on oil to 218 to 222 from 216 to 220. And as Travis said, we're not in growth mode, but the wells this year have outperformed, and we've cut more capital on the CapEx side than we have raised the production side.

So generally, completing 10 fewer wells this year than originally planned in the Permian, production up a couple of percent, but more importantly, capital down 6% or 7% from where we were before. And that translates to the 2022 plan, which is in dark pencil right now, but flat is kind of the case we're modeling. And I think generally holding that 218,000 to 222,000 barrels a day in the Permian flat with as little capital as possible is how we see it today. This -- the number we posted yesterday kind of bakes in a little bit of service cost inflation as we know our business partners on that side are going to be able to push price a little bit. But generally, really excited about a high Midland Basin percentage of wells completed next year that keeps production flat in a very capital-efficient manner.

Your next question comes from the line of Neil Mehta with Goldman Sachs.

Travis, maybe we could start on the 50% 2022 number that you threw out there in terms of return of cash flow. Do you see the potential for that to grow over time as the balance sheet strengthens? And then any early thoughts in terms of what the right mechanism is to return that capital, whether it's through dividends or buybacks, especially with the stock yielding the free cash flow yield that it is right now?

Yes. Certainly, what we try to do is allow the flexibility to make that decision when that point occurs because we want to make that decision on what creates the greatest return for our shareholders. And if you look at 2022, and you got plus 20% free cash flow yield, that would tend to think it's more of a stock buyback. But look, we're going to maintain flexibility and try to do what we've always done, which is create the framework that generates the greatest shareholder returns.

And what that number does over time, look, Neil, I couldn't be more excited about the forward outlook of the company. Even like I said at that mid-cycle oil price and a breakeven cost of around $32 a barrel, we're making a lot of really good free cash flow on a daily basis as we look out in the future. And we'll make that decision when that cash comes through the doors as to what we're going to do with it. But we've signaled very clearly an evolution in our guidance by talking about 50% going back to the shareholders. And that evolution and guidance is also reflective of a maturation of our business.

And Travis, can you talk a little bit about the cost structure of the business? How do you see that evolving over time, not only in the back half of the year, but as you get into 2022 and all the different moving pieces as it relates to both cost and capital efficiency?

I have to be honest. Our operations organization just continues to just surprise me. I mean we were -- we've -- I feel like we're already the best in doing what we do out here in drilling and completing these wells. And these guys came up with some clear fluid drilling technology that came over, quite honestly, from the QEP acquisition, and they've knocked out significant costs. I think it's on Slide 10 of our deck.

And that just continues to surprise me because we're able to back out capital in the next 6 months of the year because improved capital efficiencies against the backdrop of increasing cost of goods and services. So I don't know that it's reasonable that you can always forecast efficiencies going up and cost going down. And certainly, I don't think it's prudent to issue guidance that way. But I'm really impressed with the way our organization continues to lean in to doing more with less.

Yes. I think generally, the step change that the team has made in drilling times is going to be permanent, right? And that's going to stay with us through '22 and beyond. And basically, we can do what we once had to do with 10 rigs, with 8 now in the Midland Basin, and that's where the majority of our capital is going to be allocated for the foreseeable future.

Your next question comes from the line of Neal Dingmann with Truist Securities.

My first question is also around your comment of your plan to return 50% of free cash flow next year. Really, Travis, for you, and Kaes, I'm just wondering -- I'm wondering, will this be more of a backward-looking formula? Or I guess, more specifically, what approach will you all use for determining the timing and the type of shareholder return?

Yes, Neal, good question. I think it really comes down to a variable dividend or a share buyback. I think if it's a variable dividend, it will be backward looking the quarter that we announced will pay for the quarter prior. But if it's a buyback, I think we'll do a little math on how much free cash we're generating essentially per day and buy back that much stock on a consistent basis. So I think the Board and Travis are very focused on which one of those provides the best return to shareholders at the time. And I don't think the answer is one or the other for a permanent period of time. There's going to be flexibility to go between those. I think the only thing that is sacrosanct is the base dividend and continuing to grow the base dividend.

Great. Glad you're staying flexible there. And then my second question pertains to your comment in the release over the flat '22 production expectation versus the 4Q with a just slightly higher spend. I guess on that, while I understand some of this is driven by a change of DUCs in QEP going forward -- QEP end guide on, I should say, going forward, could you speak to your expectations for '22 baseline production decline? And maybe the rig and frac spreads involved in this and any other notable drivers sort of that your expectations you're using to achieve this?

Yes. So I'll start with the number, 10% to 15% more capital. While that's an increase versus this year, I think what's forgotten is that guide on QEP closed at the end of Q1. So we didn't have a full quarter of their capital contribution. So that's a portion of the 10% to 15% increase, I'd say about half of it. And also the other half is we did have a nice DUC benefit. If you see, we're completing 270 wells and drilling 220 this year. So that's about another $100 million benefit because when we were running as many rigs as we were into the downturn, we decided to not pay early termination fees and instead built a DUC backlog, which was the best use of investor dollars at the time, and we're taking advantage of that a little bit this year.

So I think generally, from a crew and rig count perspective, we dropped 2 rigs this quarter. We'll probably bring those 2 rigs back, but we'll probably need somewhere around 11 or 12 rigs next year and 3 simul-frac crews and maybe a fourth spot crew to execute on that plan, which is a testament to how efficient the operations team has gotten here.

Your next question comes from Gail Nicholson with Stephens.

You guys have demonstrated a very strong commitment to ESG. On the water recycling front, you're slightly above the '21 target already. Can you just talk about the future progression of water recycling? And can you remind me of the potential cost savings that exist in that world?

Yes, Gail, that's an important question. I think the -- we are above our target so far this year. With the shift to the Midland Basin, we are going to need to build out some permanent infrastructure on the recycling side to be able to not only recycle the water, but also store produced water so that we're not using -- our freshwater intensity will go down on the Midland Basin side. That process is underway. I expect that we have a nice solid connected system across kind of our Sale, Robertson Ranch and Martin County positioned by the middle to the end of next year, and that's going to allow us to up that number significantly.

So we've used 100% recycled water in the Delaware Basin. Usually, you're just pulling off the existing system. But on the Midland side, you have less water production. So I think storing that produced water and being able to use it and reuse it downhole is the next step in the evolution. And that should allow that target percentage to come up pretty dramatically over the next couple of years.

Great. And then on the electrification efforts that you guys are doing, can you talk about thoughts on the utilization of electric frac sites and drilling rigs? And then on the electrical substation work, there is an LOE benefit to that as well, correct?

Yes. I mean the electrical substation work is pretty obvious by inspection because not only is it positive for ESG and run times, but it costs significantly less than in-field power generation. So we've been working on that for the last few years now. I think generally, we've been ready to take power. It's taken a little bit of time for the coops to get to us. But by the end of this year, I think we'll have a line of sight to all of our major fields being on infield electrification.

The issue we have on the frac in the drilling side is, I think we're testing some drilling rigs on line power. They don't use up as much power as a frac crew. I think right now, our frac crews are more focused on dual fuel and Tier 4 engine capabilities versus tying into line power. I don't know, Dan, if you want to add anything to that?

No, I think that's right. We -- on the eFrac side of things, the issues generally been on the power generation side and how do we provide enough power to the fleet to run in. There's some stuff our friends on the service side are working on hard to solve that issue, but we're certainly watching it close and hope to be advancing there in the next couple of years.

Your next question comes from Doug Leggate with Bank of America.

Guys, one of the easiest ways to return value to investors is to pay down debt. Where do you see the right absolute level of debt when you consider the free cash flow you're throwing off right now?

Yes, Doug, that's a good question. I think in the near term, paying off our 2023s and having enough cash to pay off our 2024s by kind of into next year, 2 years ahead of schedule is -- feels like a very good place to be. With the breakeven as low as it is and with the delta between that and current oil prices and us not stepping on the accelerator to grow, that does give you more flexibility on the free cash side to build the cash balance and take out these bullet maturities when they come due. But I think in the near term, handling everything prior to 2025 puts us in a really good position, puts us in a gross debt position in the low $4 billion and basically a turn of leverage with a lot of free cash coming to both the shareholders and to debt reduction.

Great. Yes, I think Slide 10 is terrific. So thank you for including that in the deck. It's kind of my question, Kaes, I guess, is Slide 10, my follow-up. If you're not growing production, if you're moving to the sustaining capital sort of model for the time being, one has to imagine the underlying decline slows down some. So the bottom line is what happens to that $32 breakeven if you hold the line on production going through the end of 2022? And I'll leave it there.

Yes, good question also, Doug. I think it goes down, albeit less dramatically than it has in the past years. I think our oil decline rate quarter end to quarter end is kind of in the mid- to lower 30s right now. I think it moves down kind of 1% or 2% a year, if we keep -- continue to stay flat. But then also the other spend on infrastructure and midstream, we're going to have a little pickup in infrastructure and midstream next year with the Sale and Robertson Ranch development that we're going to have that came with no real infrastructure. So that spend comes down as well. So I think generally, we'll keep pushing it down by $1 or $2 a year. And that gives us a lot of flexibility to do a lot of things with debt paydown and free cash return to shareholders.

Your next question comes from Scott Gruber with Citi.

So the base dividend has been a core pathway for Diamondback's return cash to shareholders. So definitely nice to see another bump today. How do you think about the appropriate level for the base dividend over time? Is there a certain percentage of cash flow that you target at a certain oil price? And does this percentage change as you delever? How do you think about the base dividend?

Yes, Scott, when you go back and look at the way the Board has previously communicated this commitment, we've talked about having a base dividend that somewhat approximates the S&P yield. And then anything above that is another form of shareholder return. So that 2%, 2.5%, something like that base yield is sort of what we target for that base dividend.

Yes. I think on top of that, we think about our breakeven, too, right? So as our breakeven comes down over time, that gives you a little more flexibility to pay the dividend. Right now, 2022 dividend breakeven is at $35 a barrel WTI. As I alluded to in the last question, if the breakeven comes down a little bit, that gives you a little more flexibility on the base because like we said earlier in the call, the base dividend is sacrosanct and that needs to be protected at all costs.

Got it. And then just turning back to the '22 plan, at least the maintenance plan. I may have missed it earlier, but is there a till count? Obviously, there will be. But what is the till count at the maintenance program given the acquisitions and productivity gains that you guys have seen?

Yes. I mean it's generally flat to where we are right now and where our pace will be in the second half of the year, I mean plus or minus a couple of percentage points. But generally, we're in the kind of 65 to 75 tills a quarter, and 75% or 80% of those are going to be in the Midland Basin.

Your next question comes from line of Derrick Whitfield with Stifel.

Congrats on your strong quarter and update.

Thank you, Derrick.

Perhaps for Travis or Kaes, regarding your volume outperformance during Q2, are there 1 or 2 factors that you would attribute to that production outperformance?

Derrick, I think generally, the new wells that we brought on, on the legacy Diamondback position are seeing the benefits of the downturn last year and reallocating capital to, one, the Midland Basin, but to our best returning assets across the portfolio.

So generally, we're seeing early time is outperformance there. A good quarter all around. I mean even the base production base was -- didn't suffer from a lot of weather or unforeseen events. So I think generally, the -- on the positive side, the capital efficiency, not only on the cost side, but on the performance is improving, and we're pretty excited about what the rest of the year and 2022 holds given the development we're going to have on the assets that we acquired from QEP and Guidon.

All right. Great. And as my follow-up, perhaps for Travis. How concerned are you with the recent ramp in private activity in the Permian from the perspective of inflationary pressures and from the perspective of a potential breakdown in industry capital discipline?

So that's a real interesting question, Derrick. There's no doubt that the privates out here in the Permian are really leaning into this higher commodity price, notwithstanding the fact that the forward curve is $20 disconnected from today's price. But there's a couple of things that I think should be considered. One is, while some privates do have Tier 1 assets, a lot of the privates are more in the Tier 1.5 or Tier 2-ish, and they're not quite as productive. But the reality is, is that the effect on both Permian production and on cost increases is not 0.

It's just going to be -- it's a little bit too early to see what the effect is going to be. But I think the more quarters that pass where public companies are exercising the discipline of flat production, I think is what our industry needs. And the privates will have an impact on the overall equation. But I think the macro element won't really change.

And hopefully, the longevity of that impact as well, given the depth of inventory on the private side.

Your next question comes from the line of Leo Mariani with KeyBanc.

Wanted to jump in a little bit to the expense side of the equation here. Certainly, I know that you guys closed QEP and Guidon later in 1Q. But certainly noticed that some of your expense items in the second quarter on a per BOE basis kind of ticked up versus 1Q. I guess, most notably, your cash G&A, your LOE and even your transport costs.

Just wanted to get a sense, was there some kind of one-time items as you're kind of flushing through the integration here that might have hit some of those numbers and we should expect the per barrel cost to start to kind of drop in all those categories in the second half? Any help you can give us there?

Yes, sure, Leo. Good question. With the addition of the Bakken assets, those assets come with a much different cost structure than our traditional Permian assets. So on the LOE and the GP&T side, a little pick up there from contribution on the Bakken -- from the Bakken, excuse me.

I will say Permian LOE still remained in that $4-ish range, so you can get a feel for what the Bakken contribution was in the quarter. I would expect that to continue in Q3. On the G&A side, we did have a transition period for a good amount of the QEP employees. That transition period kind of wanes off in the back half of the year. So I think generally G&A ticks down slightly in the back half of the year.

Okay. No, that's helpful for sure. And I guess just to take a harder look at your production guidance here. Looking at your third quarter oil guide, if I just compare that to kind of your actual second quarter '21 oil number, it looks like volumes come down a little bit. I know you guys have kind of talked about holding it flat? Is that maybe just kind of some seasonality or just some kind of random variance there in the number. But generally speaking, you're trying to do your best to keep it flat?

Yes. I mean I think Q2 was a great quarter, Leo. And I think we've been very vocal about no production growth needed from the U.S. So I think we're resetting that baseline back to where we were originally in Q2. So I think there's a little bit of outperformance. And I think like we've said kind of through the year, we'd rather sacrifice capital or cut capital in lieu of growing production.

So if you keep beating production estimates and raising your baseline for staying flat, that's really growth. And so we really don't want that. So generally, I think we're pleased that we can use the 218 to 222 oil baseline for the Permian for Q3 and Q4 into 2022. And hopefully, the ops teams continue to outperform expectations and underpromise and overdeliver a bit.

Okay. That makes sense. So it sounds like there's some element of you folks basically had very strong well performance in the last couple of quarters, and that's just not something you can necessarily guide to every quarter as well.

That's right. I mean I think we expect to continue to do well, and we expect continued capital efficiency improvement, particularly with the new development we have planned in the Midland Basin. But this industry is about underpromising and overdelivering.

That makes a lot of sense. And then just lastly, on asset sales. You folks obviously talked about it being a bit of a seller's market. I know you're working hard on closing the Bakken divestiture. But is there anything else in your purview that you're looking to maybe prune late this year or into next year?

Yes. I mean I think we've had some inbounds on some noncore assets that don't compete for capital in the next 10 years of our development plan. And so I think, generally, there is surprisingly a lot of private capital looking to do things again in E&P, what a twist from 6 or 9 months ago. But I think generally, if someone wants to pay for value for something that has no value to our shareholders, on a PV basis, we'll take that call. And I think there's a couple of areas that, that might be the case. And no guarantees. We're not a forced seller, but we would do what's right for our shareholders on selling some of these noncore assets.

Your next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt & Company.

My first one is on hedging, if you just remind us on your philosophy overall there. There's obviously a lot of capacity to add as we look to the back half of next year, with the bulk of the additions earlier in the year, which maybe speaks to the strategy already as well as to how the curve sits. But just wanted to get the latest as you continue to improve the balance sheet, which obviously serves as natural protection and volatility as that gets better and better?

Yes, Jeff, great question. I think we see the backwardation in the curve. So it's hard for us to hedge further out than kind of the next 9 to 12 months. So I think generally, we'd like to be close to 50%, 60% hedged going into a quarter and build that relatively consistently over the 3 or 4 quarters prior to that quarter. What we have done is try to keep these wide 2-way collars to not take away upside for our investors.

And I think as we get closer to quarters and the time value of money goes down, some sort of deferred premium puts make sense to layer on top of the wide 2-way collars. I think generally, we feel really good about where the balance sheet is going to be at the end of the year and the free cash flow generation even at $50 TI next year. And so that's kind of the downside we're trying to protect.

Got it. And then secondly, I just wanted to see if there's anything you could dig in on a bit more just on the moving pieces on cost inflation that you spoke to. Just if there's anything incremental you could speak to on what's moving currently on the services side of things, in particular?

Well, it's been very visible on the steel, diesel side and the raw material side. I think, generally, the steel inflation, in our opinion, needs to slow down at some point. But I think that the cost inflation is going to flip to the more service-oriented lines on the labor side and on the pieces of the service world that go up with rig count.

So I think we held off long enough on that front. And I think the service industry is able to push a little price here on that side. But I think most importantly, what we've done on the Midland Basin side is the lowering of days to TD has counteracted any of that increase so far.

Your next question comes from the line of Charles Meade with Johnson Rice.

I'd like to ask one more question, maybe from a different direction, on that -- on the 50% of cash -- free cash return to shareholders in '22. I recognize that you guys are going to keep your options open and you're going to have to observe the conditions present then when you make that decision, but can you share any kind of preferences or maybe even a framework since that's an idea that you guys have used on how you're going to approach that decision?

And kind of thinking along the lines of, the books will tell you that share buybacks are more tax efficient but share buybacks have a little bit of a bad reputation, not just in the E&P business, but also in other industries as being pro-cyclical. So how are you guys going to approach that question? And are there any preferences for how you do it?

Yes. I mean that's a really good question, Charles. And it's a highly debated topic internally on pro-cyclical share buybacks. I think what's changed a little bit in the business is we're no longer growing as fast as we can and spending capital to grow and return cash to shareholders. I think generally, now with capital being constrained to maintenance, you have a lot of flexibility above that.

At the end of the day, we fundamentally have to look at what our NAV looks like on a mid-cycle oil price and mid-cycle commodity price environment. And if we're trading below that, even with oil where it is, then the buyback makes sense because that return on a PV basis is a better return to buy in stock market than buy in the ground. So that's kind of the analysis that's going to go into it. Today, it feels like a buyback is the right way to go. But again, it's still August 2 and 3 today, and we have some time to make that decision.

Yes. And Charles, I can't emphasize enough from the Board's perspective, that decision is going to be made on what drives the greatest shareholder value. And yes, there's technical questions that need to be addressed. But at the end of the day, our responsibility is to generate differential shareholder value. And that's still the problem statement that we'll solve with our shareholder return program.

That is helpful. And then a follow-up. This -- you -- feel free to punt on this if you don't think it's productive. But Travis, you spent a fair amount of your prepared remarks talking about your ESG and specifically, I was -- my attention was caught by your talk about this new tankless -- this tankless design. And I'm curious, when you look at the cost, the incremental cost of that, have you matched that up against the cost of perhaps you guys talked in past quarters about buying carbon offset credits. Is that a comparison you guys make? And if you do, how do they stack up?

Yes. It's part of the calculus, but it's not an either/or, right? The fundamental decision to move into the carbon credits was a recognition that we're doing things operationally in the field that's going to get us to where we want to be over the next couple of years. But this is much more tactical. This is a specific strategy that we're deploying that has meaningful CO2 and flaring reductions associated with it. And that's why we shared the statistics of reducing emissions by 90% on our atmospheric tanks. We think it's really a good way to go.

And we want to try to be as communicative as we can on this because this isn't a Diamondback secret nor is it something that we're trying to position Diamondback favorably for. This is an industry-wide issue. And I think the solutions need to be industry-wide as well, and we want to be as collaborative as we can be and share these learnings that we have, and this is a very good form to be able to share those techniques. In fact, some of these came probably from ideas that we got from other operators.

So look, I'm very, very proud of the efforts and the results that Diamondback has generated, particularly since we drew a line in the sand in 2019. And I'm also really proud about what our industry is doing as well. And the narrative has certainly moved away from us or maybe we didn't take advantage of it as an industry to control that narrative, but we've got to do a better job of saying, we recognize what it is we're doing has an environmental impact and more importantly, that we are spending dollars and applying that same innovative thought processes that got us horizontal drilling and fracking and the success we've enjoyed by that. So we're really good problem solvers. And we're going to communicate each quarter ways that we're solving this problem on our environmental responsibility objectives.

There are no further questions. I will turn the call over to Travis Stice, CEO.

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