Diamondback Energy, Inc. (FANG) Q1 2021 Earnings Report, Transcript and Summary

Ladies and gentlemen, thank you for standing by, and welcome to the Diamondback Energy First Quarter 2021 Earnings Conference Call. [Operator Instructions]. I would now like to hand the conference over to your speaker, Adam Lawlis, Vice President of Investor Relations. Please go ahead.

Thank you, Phyllis. Good morning and welcome to Diamondback Energy's First 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; and Kaes Van't Hof, CFO. 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 first quarter earnings call. Diamondback had a successful first quarter, continuing to build off the momentum generated in the back half of 2020. Operationally, we are hitting on all cylinders. We were able to effectively navigate a once-in-a-generation winter storm while keeping well costs and cash operating costs near all-time lows. We closed both the Guidon and QEP acquisitions in the first quarter and are very pleased with how the integration efforts are progressing. We are achieving our synergy targets ahead of schedule and in excess of the $60 million to $80 million of annual cost savings we highlighted when the deals were announced. Yesterday, we also announced 3 noncore asset divestitures for gross expected proceeds of $832 million. By selling these noncore acreage positions in such a timely and opportunistic manner, we were able to take advantage of a strong A&D market and generate attractive cash returns for Diamondback shareholders. We anticipate using the combined proceeds from these noncore asset sales to accelerate debt reduction. As we discussed last quarter, even though oil demand has shown signs of recovery from the depths of the global pandemic, oil supply is still purposely being withheld from the market, primarily through the actions of OPEC+. As a result, we continue to believe we do not need production growth and will hold our pro forma fourth quarter 2020 oil production flat through 2021. Due to the complexity resulting from the timing of the QEP and Guidon acquisitions as well as the announced divestitures, we have instituted quarterly production and capital guidance for the first time. For the second quarter, we anticipate spending $350 million to $400 million in capital and producing 232,000 to 236,000 barrels of oil a day. This production range accounts for a full quarter of contribution from QEP's Williston asset and approximately 2 months of production from the announced noncore Permian asset sales. Looking at the full year of 2021, our free cash flow profile continues to improve. In the first quarter, we generated approximately $330 million of free cash flow, marking the third consecutive quarter of significant free cash generation. At current strip pricing and accounting for the Williston divestiture, we expect to generate approximately $1.4 billion in pre-dividend free cash flow this year at a reinvestment ratio of below 55%. In March, we executed a successful tender offer and refinancing of all of QEP bonds and one of Diamondback's existing bonds. This refinancing equates to $40 million of annual interest expense savings and extended our average debt maturity by 3 years. Today, we have 3 debt maturities that are callable before the end of this year: $191 million due later this year, $650 million due in 2023 and $432 million due in 2025. We expect to use cash on hand from internally generated cash flow as well as proceeds from our asset sales to retire these 3 tranches of bonds, reducing our absolute debt load and further strengthening our balance sheet. Now turning to ESG. We recognize the importance of operating with the highest level of environmental responsibility and continue to make progress on our ESG initiatives. We flared 0.75% of our gross gas production in the first quarter, a decrease of over 85% from 2019. Flaring is the biggest driver of our CO2 emissions. And while we are happy with our progress on our legacy acreage, we still have significant work to do on our recently acquired positions as we move to reduce our Scope 1 GHG intensity by at least 50% from 2019 levels by 2024. We've also committed to reducing our methane intensity by 70% over the same time frame. In the first quarter, we continued spending capital to retrofit our older tank batteries with air pneumatic devices as gas pneumatics account for 50% of our methane emissions. We also signed a contract to conduct quarterly flyovers of all of our tank batteries to more frequently check for equipment leaks, improving our maintenance practices. Our Net Zero Now initiative is also underway, which means every hydrocarbon molecule produced by Diamondback is anticipated to have 0 net Scope 1 carbon emissions from January 1, 2021 forward. While we recognize we still had a carbon footprint, we have already purchased carbon credits to offset remaining emissions and ultimately plan to be a fast follower in investing in income-generating projects here in the United States that will more directly offset these remaining Scope 1 emissions. To finish, the first quarter was busy and productive. We generated substantial free cash flow, kept our capital and operating costs down, extended debt maturities, added Tier 1 inventory and divested noncore assets. All the while, our strategy remains the same: operate in a prudent and sustainable manner, spend maintenance capital to hold production flat and use future free cash flow to return cash to shareholders and reduce debt. With these comments complete, operator, please open the line for questions.

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

Quite, you and the team, a bit emphatic about what I would call macro speaking that the world really does not need any more oil growth anytime soon. So my question is really pertaining to this. Do you all believe your operational program is as optimal at this lesser pace than if you had a more multi-rig larger frac plan in several of your areas and whether business have much impact on your cash cost?

Sure. I think if you look, Neal, just at our cash cost that we printed this quarter, you would say that there's not been any leakage or any cost pressure that were -- that has translated into execution slippage associated with the lower activity rate. I mean, Neal, if you look at rolling into 2020 before the global pandemic hit, we were running 23 drilling rigs and, I don't know, 8 or 9 frac spreads. That was a pretty quick pace. And I've actually been really pleased with -- as that pace was reduced, in some cases, dramatically last year. Even as we've entered into this year, we really seem to be at a pretty efficient frontier in both rig activity and frac spreads with 11 rigs and 3 to 4 frac spreads. So I think if you just keep watching our numbers that we print, I think that will be a good indicator of whether or not we're being efficient. And certainly, for the first quarter -- in the fourth quarter also, the numbers really look strong.

No, I agree. I agree. Okay. And then now that Guidon and QEP are in the books, I'm just wondering, could you or Kaes comment anything you all see that's different or surprised you from the assets? Maybe specifically, if you all still believe there's as many quality locations? And how do you sort of rank that inventory versus existing?

Yes. Certainly, that narrative hasn't changed at all. In fact, it's probably gotten a little bit better. And I'll tell you, I was very complementary of the QEP team at acquisition announcement time and again, during our February call and our April update. Operationally, they were doing some really efficient things. And just looking at the drilling report this morning, QEP's always use water-based mud. And Diamondback now, we've adopted it and we're on our first or second well with water-based drilling fluids that quite honestly, QEP is helping us with. And so far, really, really impressed with the improved efficiency using water-based mud. So that's been a nice add to what I thought was already a really efficient Diamondback legacy operations team. This looks to be a little bit of a stairstep in the right direction.

Your next question comes from the line of Arun Jayaram with JPMorgan.

Travis, I guess the shoe is on the other foot this time with Diamondback on the other side of marketing assets. I wanted to get your thoughts. Obviously, you guys have the data room for the Bakken sale. You sold some noncore Permian assets as well. What is your sense of the A&D market today? We've seen a couple of very large Permian trades, DoublePoint and Vitol. And I guess I wanted to get your sense of, do you see more of these private-to-public trades occurring this year? And what criteria that Diamondback will use to evaluate A&D activity?

Certainly, we were really pleased with the interest in the Bakken divestiture process. Now granted, we were the beneficiaries of commodity price run-up and some previously announced deals in the Bakken that I think put some wind at our backs. So that -- I think that piece of the A&D still seems to be pretty frothy, particularly on the PDP-focused type of divestitures, a lot of interest in that. But specific to what Diamondback is looking for on a go-forward basis, we still remain very resolute in our strategy that it's got to meet internal objectives like free cash flow, and it's got to be return accretive on a per share basis. And when you look at the combination, we've got to accelerate return of free cash flow. The larger trades that -- particularly the ones that you referenced, it's -- the quality of assets that fit for capital in Diamondback's top quartile are probably fewer than greater. And the prices that were recently announced on some of those trades might have coiled some of the activity for a little while anyway. But I think as long as we can demonstrate that were being accretive on a per share basis and that we're accelerating return of free cash flow, we're going to continue to look in the Permian Basin. But the opportunity set is pretty narrow right now. Kaes Van’t Hof: But most importantly, there has to be inventory that competes for capital right away, right? We -- while this industry has moved towards financial metrics, that can't be the only numbers that we look at when we think about what makes sense in terms of an acquisition and sticking inventory in the bottom quartile or bottom half of our existing inventory just doesn't make sense to us from a returns perspective.

Makes sense. Kaes, I'd love to get your thoughts on the updated inventory disclosure, quite a few changes here. It looks like in terms of -- focusing on the Midland Basin, you increased your inventory count by just over 150 net locations. I know that the lateral lengths increased a little bit and perhaps, the Delaware declines just reflect some of the A&D activity. But give us some thoughts on the updated inventory kind of snapshots, kind of the key takeaways. And I do sense that you perhaps are using a little bit wider spacing for some of the acquired assets from QEP and Guidon? Kaes Van’t Hof: Yes. That's right. We hadn't posted a full inventory update since the beginning of 2020. So this was the first update post the 2 deals. I'd say, generally, we spend a lot of time looking at our development as well as offset development, particularly in the Midland Basin. And I mean, I think our focus is the best zones can still handle kind of 660-foot spacing, which is as tight as we've kind of ever gotten. But we kind of realized that maybe the secondary zone should be spaced a bit wider. And so that's reflected in that inventory numbers we've put out. So secondary zones that are getting codeveloped with the primary zone, which we still think is the right thing to do, are getting spaced at 5 to 7 wells a section rather than kind of 7 to 8, which is the best zones.

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

Taking a look at the slides here, you show at a $60 WTI price in reference to this driver in your script of north of $1.4 billion of free cash flow before the dividend this year. But this year, you are burdened by hedges. I was curious if you could provide some perspective around what open EBITDA would look like in that type of environment. And then also your perspective on use of proceeds of all this free cash flow and the asset sales, your framework around returning some of this excess capital to shareholders. Kaes Van’t Hof: Yes. That's a good question, Neil. We're probably sitting on about $450 million or $500 million of hedge losses for the rest of the year at strip today for the balance sheet. So that's the drag on free cash this year. I think it's fortunate that we are losing money on hedges compared to where we were a year ago, but unfortunate that we do have to write the checks. But overall, I think if you add that number back to the free cash number, you can get a pretty clean look at what the future might hold on an unhedged basis.

That's great. And that ties into the follow-up around capital returns. Talk about how quickly you can get to the leverage levels that you're targeting. And then there are a lot of different options at that point, right? You could think about a buyback, you can think about a variable dividend. Recognizing it's too early to commit to that until you hit your debt target, just walk us through your framework about the different options that are at your disposal.

Yes. Sure, Neil. I think it's good for our industry that we continue to talk about investors recouping a return for the money that they've asked us to deploy. I think that's good for our industry. And you're right about reaching certain debt targets and these announcements that we laid out yesterday to simply accelerate the time frame at which we can hit those debt targets. I think the callable debt reduction of $1.2 billion or more by the end of this year is going to put us in a favorable position to start talking about what the next step is. I also think that our industry has seen a lot of interest in laying out a formula for how capital allocation is going to go or capital allocation and returns to shareholders is going to go. And I wish that our industry was as simple that you could put a formula in place, and formulas work as long as the world doesn't change. But in our business and a commodity-based business, we know that our world does change. So I'm always a little leery of trying to promise delivery on a formula when we know the world is going to change. But the options are very clear. The strategy around the variable dividend is part of the future discussions at the Board level, as is share buybacks, and most importantly, like we've always committed to, continue to lean into our base dividend. So we're very pleased that we're able to accelerate our debt reduction targets with kind of a very positive divestiture number. And we're going to continue to deliver on -- through our performance and try to avoid making promises multiple quarters in front of us.

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

Travis, after the QEP deal, you suggested that your breakeven to sustain your production would potentially move lower. Just wonder if you could give an update in light of your comments around synergies last night as to where you see that settling out.

Well, certainly, the synergies that were in excess of what we promised stem from the refinancing of the locked QEP's debt. I think we talked $40 million. We didn't even describe that as a synergy at acquisition announcement time. The specifics around lowering the breakeven cost has to do with our capital allocation of moving rigs into this newly acquired acreage, both Guidon and QEP. And while I can't formulaically give you dollars and cents how much our breakeven cost has come down, we do know that doing higher cash flow-generating projects at higher rate of return is going to translate to a lower breakeven cost.

Okay. It seems to us you've won by about $1 or $2, but we'll take that off-line. My follow-up is also related to I guess some of the comments at the time of the QEP deal related to infrastructure and maybe the opportunity to drop or look at dropping down some assets to Rattler and maybe some royalty opportunities for Viper. I'm just wondering if you got any update you can share as to how you're thinking about that. Kaes Van’t Hof: Yes. Doug, there's not a lot on the Viper side to drop down at the Diamondback today. QEP and Guidon, they, in different ways -- QEP is on a lot of large landowners in the Permian that have been around for a long time and not looking to sell their minerals, and Guidon had a sister company like a Viper that was buying minerals. So on the Viper side, we're certainly sourcing minerals at the Viper level under QEP and Guidon acreage, but there won't be a drop down. And then on the Rattler side, QEP, we've been pretty vocal that QEP did a really good job on infrastructure. I think we've learned a lot on the recycling side from them, who's going to boost our Midland Basin recycling program significantly. And eventually, those assets should probably be long in Rattler, but I think it's going to take a few more quarters for us to get that -- all that worked on and then eventually, drop it down.

Your next question comes from the line of Gail Nicholson with Stephens.

Every quarter, efficiency gains are achieved. Where do you think you are in that learning curve? And are you trying any new technologies that could prove to be beneficial for future improvements? Kaes Van’t Hof: Yes. Gail, I mean, I think Travis kind of said it earlier in the call, but bringing the QEP team in the fold, just like when we brought Energen in the fold, we don't need to be the best, we just want to learn from the people that we add to the team. And we learned a lot from Energen, and then we recently just learned a lot from QEP. So as Travis was mentioning, water-based mud on the drilling side, some drill-out techniques on larger pads that are saving us some time. On the cementing side, I think we've learned that we can batch drill and batch cement, which saves us time, and this all reduces time on location and increases the efficiencies, which is why Danny's team on the drilling side is getting kind of ahead of the 2021 program early in the year, which I think is positive.

Gail, back at the Energen announcement time, I think I used the phrase that we checked our egos at the door when we brought the Energen team on board. And this is just really -- as Kaes highlighted, this is another example of checking your egos at the door, and let's just try to figure out what's the best way to do this for our shareholders. And really proud of the operations organization. Once again, they've done so. And we've not really had the QEP team inside the fold for very long, but that they're already making a very positive influence.

And then circling back to the inventory. With the improvement in oil prices, Do the secondary zone see a potential uptick in capital allocation in '22 forward? Or should we still be assuming that the primary zones are the target for the foreseeable future? Kaes Van’t Hof: I think just generally, we're very focused on co-development between zones, particularly in the Midland Basin, and the secondary zones get spaced a little wider. I think, Gail, we did a lot of work at various oil prices on inventory and spacing and EUR per foot. And we kind of found that the benefit to IRR outweighs any benefit to NPV from going tighter. So no one got mad at you for drilling wells that were too good. And so I think we're going to stick with that strategy, particularly with how much undeveloped acreage we got with the QEP and Guidon deals.

Your next question comes from the line of David Deckelbaum with Cowen.

Just curious, the deal with QEP only closed, I guess, about 7 weeks ago now. As we think about your development plans on those assets, when would be like a decision point where we might see a shift of activity either more towards county line or some other areas that you're learning from that might have surprised you with what you're seeing today versus pre-deal so we could start thinking about how '22 looks? Kaes Van’t Hof: Yes. David, I think you start to see that in terms of the wells that we're going to be drilling now, but you won't see it in terms of production until kind of Q4 '21, early '22. I think we're trying to get as many rigs as we can in the Robertson Ranch/Sale Ranch area in South Central, Martin County, some big pads and efficient development going to be headed that direction. Rigs are there right now. I think when it comes to kind of county line in the northern part of Martin County, we've done a lot of technical review with the QEP team and our team, and they've done some things in the shallower zones that we like, some targets that we like in the county line area. So I think you'll see more of the Wolfcamp A, Middle Spraberry, Dean, LS work in the county line area and then more of the deeper Wolfcamp and Lower Spraberry in the Robertson Ranch area.

Appreciate that. And if I could just ask one on just the capital program this year. Just curious, like relative to your guidance on footage cost of $520 to $580 in the Midland and $720 to $800 in the Del, where you guys are today? Because as I look at the rest of the year, it seems to certainly be implying like a back half-weighted program. Does that stairstep up each quarter now going into the end of the year? Because I guess we're thinking about sort of like the sustaining quarterly run rate that we should expect going into next year. Kaes Van’t Hof: Yes. That's a good question as well. I think I'll take the well costs first. We put a lot of look at well costs in the deck. Midland Basin was around $530 a foot, and Delaware was actually below the low end of the guide, which I think was just a really good quarter operationally, a little lower sample size as well. But as you think, we did put out Q1 CapEx of $300 million in Q2, implying $375 million at the midpoint. So that would imply we're going to spend $1 billion in the back half of the year. And I would say there's certainly some conservatism on our side. We've been very vocal that we will cut CapEx to keep production flat rather than grow production and spend more dollars. But the ancillary stuff, environmental, infrastructure, midstream, non-op is going to pick up a bit in the middle of the second half of the year, and that, on top of the couple of quarters of true pro forma QEP and Guidon and Diamondback activity, will result in capital coming up slightly throughout the year. But yes, we're off to a pretty good start in the first half.

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

Congrats on your transactions. Perhaps for Travis or Kaes, following up on the earlier A&D question, but taking it a slightly different direction. In your view, did that larger transaction tilt the environment to a seller's market? And if so, would it make sense to pursue smaller divestitures to further improve your balance sheet? Kaes Van’t Hof: That's a good question. Certainly, the market has improved dramatically, and that's why we kicked off that -- the Upton County process and the non-op New Mexico process that, we thought in the back of our minds, were sale candidates for years, but the last 12 months have not been conducive to selling cash flow. I think the trend, Derrick, is that a lot of private capital has moved towards buying PDP-heavy assets and distributing that cash flow to their LPs or to their shareholders. And when everyone's doing that, you have a lot of competitive tension in the process. And so that allowed us to get pretty competitive bids on all 3 assets, and we're pretty happy. But I think for us, anything else that's a sale candidate in the Permian has real undeveloped value, and that's not something we're looking to sell right now because I think the market for that is less competitive than a PDP-heavy market.

That makes sense. And Travis, for my follow-up, I'd like to pick up on a comment from my discussion yesterday. As you guys progress your plans to invest in income-generating projects that will more directly offset Scope 1 emissions, could you speak to the nature of your industry discussion since Q4 and how that plan might take shape longer term at Diamondback?

Yes. Specifically, for Diamondback, we talked about CCUS technology and emerging trends with that. I think a good analogy for our Diamondback shareholders would be to see how Rattler participated alongside subject matter experts on long-haul pipe. We don't expect to become subject matter experts in income-generating projects, CCUS type projects. But we do anticipate aligning ourselves with those that are -- those experts and try to do those technologies. That is -- those emerging technologies are not months or -- they're quarters away. And there are things that -- there's new technology emerging, and we're trying to stay abreast of it. And when I talk to my industry peers, it's a very similar tact that they're taking as well, too, is to try to be extremely fast followers and figure out what emerging technology needs you need to lean into the soonest. But I think it's an industry trend for sure.

Your next question comes from the line of David Heikkinen with Heikkinen Energy Advisors.

Any thoughts on a drop-down of your QEP Midstream assets or formerly QEP assets into Rattler and timing of that? Kaes Van’t Hof: Yes. David, it's certainly on the schedule. The other activity is getting Bakken sold and getting the refinancing done took priority, but the team is doing their work. I think as you think about the drop-down, we're going to have a very large block across half of Martin County, and so we want to get the engineering right and also build out recycling infrastructure across that block to be able to store, produce water and reuse it in the Midland Basin. So I think it's a couple of quarters away, but certainly, it's on the docket.

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

I wanted to follow up a little bit on your comments around synergies. You guys talked about that you're ahead of expectations of the $60 million to $80 million. Clearly, you pointed out the debt refinance split. Perhaps maybe you could talk a little bit more to kind of the G&A and the operational synergies. Are we going to start to see those numbers show up as soon as second quarter earnings when you report? Do these come more in the second half of the year? And can you maybe provide a little bit of color just on the operational synergies and specifically, where those will come from? Kaes Van’t Hof: Yes. Leo, I think we predicated the deal primarily on G&A and interest. QEP was a low-cost operator just like Diamondback. So unlike Energen, we didn't come out and say, "Hey, we're going to drill 2,000 wells $200 a foot cheaper." But the G&A stuff will start to show in Q3 and Q4. And obviously, the interest has happened today. I think there's probably some upside on the operational front when -- if and when a drop-down happens at Rattler, and being able to connect all of our midstream systems without spending extra capital to add that capacity could be an upside surprise.

And also, Leo, just operational, what we talked already on this call about the water-based mud, using big rigs for drill-out, some of the other cementing practices that Diamondback is now adopting from QEP learnings, those all translate directly to lower dollars per foot, and that's -- those are direct synergies as well.

Okay. That's helpful. And I guess just on the LOE side, you guys certainly spoke to just great cost control in the first quarter. Certainly couldn't help but to notice that your first quarter LOE was below your full year guidance despite the fact that we had a, call it, 100-year storm in the first quarter. So certainly, you guys -- looks like you guys are doing a good job executing in the field. Do you guys feel like you're maybe set up to come in a little bit below that LOE guidance for the year? Or are you going to see an uptick once the QEP and Guidon assets kind of take full effect here in the second quarter?

Leo, it's Danny. The LOE in the first quarter, we certainly saw some surprising benefits throughout the year during first quarter from some electrical contracts and other things throughout the storm. We do expect that we'll see a little bit of increase from that number from the Guidon and QEP assets. Mostly the Guidon assets have a little bit higher lifting cost than what we've traditionally seen at Diamondback. But we like the low end of that guide right now. And as we learn kind of more about the assets and where their lifting cost is going to settle as we get them integrated, we'll update the market.

Your next question comes from the line of Richard Tullis with Capital One Securities.

Just one question for me, kind of following up on the earlier ESG discussion. And you mentioned, Travis, in your opening comments about being the fast follower in the investment side. So you generated strong free cash flow, and it certainly looks like that continue given where commodity prices are. How large of a part of the FANG story could investment in renewables or CCUS type projects or entities develop into, say, over the next 2, 3 years?

Yes. That's a fair question, Richard. But I just -- I don't know what that number is going to look like yet. There's too much that's still emerging in the form of new technology development. And I know it's important, but in terms of what percentage of our capital is going to be allocated towards that, I'm not comfortable communicating that yet because it's -- quite honestly, we don't know what that answer is. Kaes Van’t Hof: Yes. I mean I think what's most important, Richard, is if our Scope 1 emissions go down, you have less incentive or need to invest on the other side to offset it, right? So today, $15 million a year is going into the tank battery side. And I think we put out some new numbers that we're going to replace 200 generators in the field this year and move that to line power. We're then moving towards a Scope 2 emissions number and how we're going to get that down through sourcing electricity through renewable sources. So while Travis says we're going to be a fast follower on the investment side, we're certainly going to be a leader in terms of spending dollars in the field to clean up and reduce our intensity on what we can control.

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

A quick one for me and then maybe a more open-ended one. You guys -- you've sold or agreed to sell close to $1 billion worth of assets, but your CapEx guidance is unchanged. So does that mean that you essentially had de minimis CapEx on those assets that you're divesting? Or is there some reallocation going on? Kaes Van’t Hof: No. It just means they were noncore, Charles. The key to an asset sale is does that asset compete for capital with the rest of your assets, and these 3 assets did not. I'd say some of the New Mexico acreage was really good acreage. But we're not a non-op producer. So we sold stuff that sits lower in the inventory ranking, and we're going to reinvest it at this time to pay down debt and generate free cash to return to shareholders.

Got it. And then Travis, if I could go back to comments in your prepared remarks. You've mentioned before how oil inventories, global oil inventories and also U.S. inventories are looking in -- looking better, but we're still looking at some supply artificially being withheld from the market by OPEC+. I want to understand a little bit more of your thinking because in my way of looking at things, if you wait until OPEC+ has 0 barrels off-line, at that point, we're probably in a spike scenario. And I don't think you maybe need to wait that long. And so maybe it's not a binary thing that you have to wait until OPEC spare supply is 0. But can you tell me about how it looks from your point of view? And what any threshold or series of thresholds would be?

Yes. Certainly, I wish most of the decisions that I had to answer were binary, yes or no type of questions, and this is not one of those. Just from a macro perspective, you know that OPEC+ is effectively controlling the market right now, and it's having an outcome of reduced inventories. And against the backdrop of still a fledgling oil demand recovery, which quite honestly, might be negatively impacted by the unfortunate outbreak in India, it's just still -- in our opinion, it's still too early to be talking about growth. There's no clear signal. Now do we need to get to 0? With OPEC+ being retailed, I don't know that, that's the right answer either. We still got to assimilate 1 million or 1.5 million barrels a day of our and production likely coming back on. So it's an evolving question. But as it pertains to Diamondback, there's no clear signal for us to grow volumes, and it's unlikely that you've seen any of those signals this year.

[Operator Instructions]. Your next question comes from the line of Paul Cheng with Scotiabank.

Travis, just curious that you talked about the near-term debt reduction for this year, $1.2 billion. Longer term, what will be the right capital structure or the debt level for Diamondback?

Yes. I think that's certainly an evolving question as well but -- or a revolving answer as well. But certainly, we wanted to get our absolute debt reduced to where we were before the QEP and the Guidon acquisitions, which were almost there. I think in terms of leverage target, of course, leverage is a function of EBITDA, a function of oil price. But leverage targets, the Board mandate has had us below 2x since the IPO, and we'll be there now sooner rather than later. I think the longer-term run rate for leverage is probably 1 or below, and it's going to take multiple quarters for us to get there, but certainly encouraged with the way our forward outlook plan looks and our debt retirement strategy.

Just curious of that because I think that's one school of thought in a highly volatile sector like oil and gas. The best hedge is actually not for the paper market hedging program, but using a fortress-like balance sheet. So on that basis that -- will Diamondback be interested or consider to drive the net debt down to a really low level so that you can get away from the hedging program totally and also position yourself to be much stronger and have far more flexibility and opportunity when you get to the next downturn? Kaes Van’t Hof: Yes. Paul, I mean, I don't know if that's an either/or answer, right? I think it's an and answer. And like Travis was saying, I think something like a turn of permanent leverage at high 40s WTI is a pretty good hedge, natural hedge for the next downturn, but I think you also need some sort of put protection or big insurance policy that if things go really south like they did in 2020, you're still protected. So I think it's a combination. I think hedges will still be a part of our story, particularly with a growing dividend and investors demanding capital be returned to them. You have to protect that cash flow. The only way you can in the paper market, you might do a wire collar or buy puts that are pretty cheap. But I think, again, it's kind of an and discussion.

And with your structure in Rattler, with more than 7% dividend yield there, so strategically, does it really have the benefit for you to keep it as an independent entity and drop down assets there? I mean does it really gain anything from a capital efficiency standpoint? Kaes Van’t Hof: Well, we sold everything we had in that business for 29% of the business. So I think for Diamondback shareholders, the IPO of Rattler was certainly a win. I think we have to look at the subsidiaries consistently in the lens of what's the best thing for Diamondback shareholders and what's the best thing for the shareholders of the subsidiaries. Fortunately, we've created these vehicles without major conflicts of interest. And traditionally, they traded at higher multiples than the parent. So they've been, I'd say, successful investments. But yes, we got to think about what those -- what value those add. I think in an acquisitive environment, they've added value. And I guess, if we're acquiring less, we'll have to reassess that. But right now, they're still strategic, and we have a lot of value for Diamondback shareholders sitting in the stock of those two companies.

Okay. All right. Final question for me. Can you discuss the process when you sell the Bakken asset? Maybe we are wrong, but when we're looking at the future strip, that for the next 12 months, the Bakken asset that you sold should be able to generate EBITDA of about $250 million to $300 million. So it looked like you sell for 2.5 to 3x turn. That seems a bit low. So just trying to understand the process. Kaes Van’t Hof: I think the process was very competitive. This was an asset that wasn't going to be getting capital from us. So I think, Paul, we were very vocal that the Bakken was going to be held for sale. I'm personally very pleased with the price we received. It seems like in the fall, everyone was saying, "Oh, you can't sell anything for better than PDP, PV-15." And like I said earlier in the call, I think this industry can't move towards only looking at financial metrics. NPV and NAV still matter. They probably play a lower role than they did in the past. But financial metrics alone isn't going to be the reason why we sell an asset we deem noncore when we did an acquisition a couple of months ago.

At this time, there are no further questions. I would now like to turn the call back over to Travis Stice, CEO, for closing remarks.

Thank you again, everyone, for participating in today's call. If you have any questions, please contact us using the information provided.

Thank you. That does conclude today's conference. We thank you for participating, and you may now disconnect.