Diamondback Energy, Inc.

Good day, ladies and gentlemen, and welcome to the Diamondback Energy first quarter 2020 earnings conference call. This time all participants' lines are in a listen-only mode. After the speaker's presentation, there will be a question and answer session, and to ask a question during the session, you need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. And as a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawless, Vice President, Investor Relations. Sir, you may begin.

Thank you, Chris.

Good morning, and welcome to Diamondback Energy's first quarter 2020 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 Dice, CEO, and Kate Banthoff, 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 indicating 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 Sykes.

Thank you, Adam, and welcome to Dinovac's first quarter earnings call. Before we get started, I'd like to take a minute to extend our thoughts and prayers to all of those affected by the coronavirus pandemic. The challenges presented so far in 2020 are unprecedented, but our perseverance is evident in the decisive actions we've taken to preserve our strength through this cycle. Our organization has now been working from home for almost two months, and I can honestly say the business has performed extraordinarily well given the circumstances. Our teams have reacted quickly to the rapidly changing landscape and adjusted our operating and capital program in almost real time to prepare Diamondback for the commodity price weaknesses we are experiencing today. Crises have a way of revealing character. And we have witnessed this across our organization. And I'm confident that you, as our stockholders and owners of the company, would be proud of how our employees have responded in supporting the communities where we live and work. We have an organization of motivated and exceptionally talented people. Turning to the first quarter, Diamondback grew oil production 3% quarter over quarter, and unhinged oil realizations averaged 99% of WTI. our highest oil realization in almost two years. We turned 80 operated wells to production in the quarter as our operations machine was executing efficiently before commodity prices weakened and we immediately ceased all completion activity in March. We expect to complete less than 10% of our 2020 well count in the second quarter, with the only planned completions for the purpose of leasehold retention. Because Diamondback did not slow operations in the fourth quarter of 2019 and maintained continuous operations with over 20 rigs and eight completion crews running through most of the first quarter, capital spend was $790 million, or a little over 27% of our original capital budget for the year. When commodity prices dropped, we took immediate action and dropped all of our completion crews per month and are working down our rig count as quickly as possible without paying early termination fees on existing rig contracts. While we are running 14 rigs today, we will exit May running 10 rigs and enter the third quarter running 8, down over 60% from the beginning of the year. We also plan to enter the fourth quarter running 7 rigs, with the ability to reduce further into 2021. This rig count reduction, combined with our current completion schedule, means we will exit 2020 with over 150 ducts. This is over 100 ducts above what will be required as a standard working duct inventory for a three to five completion-proof program, which is our base case program exiting 2020 as we see things today. While this may be a drag on overall capital efficiency in 2020, it will give us significant flexibility and be a benefit to capital efficiency over the next couple of years, particularly in 2021, as we navigate an uncertain forward outlook. Because CapEx is a cash flow statement member, you will start to see our reduction in activity benefit our cash spend at the end of the second quarter and through the back half of 2020. As a rule of thumb, activity reductions today are reflected two months later in cash flow statements. while commodity price fluctuations are realized in the month in which they occur. As a result, our capex spend will be weighted toward the front half of 2020, with the third quarter beginning to truly reflect the significant activity reductions that began in March and continued into the second quarter. Fountainback is curtailing gross operating production by 10 to 15% this month due to the uncertainty in the forward oil price contract and the risk of low unhedged realized oil prices for the month. With differentials in role already set heading into the month at over $10 off WTI, the risk of WTI prices declining further outweighs the benefit of producing as much as possible into extremely low unhedged realized prices. We have hedged production for nearly 100% of expected oil production before curtailments, including basis and role protection, and therefore can monetize in the money hedges without materially impacting cash flow when production is curtailed. When assessing where to curtail production, we focused on fixed and variable operating costs and underlying marketing contracts, choosing the slow production where we do not need to spend significant dollars to do so. We will continue to monitor future prices As we prepare to nominate production for June and the months ahead, and should meaningful curtailments persist or accelerate, we will plan to update our investors accordingly. Looking ahead, due to the volatility in commodity prices, there is significant uncertainty in our full business plan, and we are planning to stay flexible on how many completion crews we bring back to work in the second half of the year, and which months those crews get back to work. We'll need to see some stability in the forward curve before making this decision. In the interim, we will continue to focus on what we can control, which is our cost structure, and preserve as much liquidity as possible. We ended the first quarter with $1.9 billion in liquidity and only have one term debt maturity due in the next five years, a $400 million maturity due September 2021. With our reduction in spending, current hedge protection, and suspension of our buyback program, we expect to maximize liquidity and retain cash to pay down debt. Our dividend remains our primary return of capital to our equity holders, and the Board of Directors has decided to maintain the dividend based on the current forward outlook. Paying our interest expense, retaining our people, and paying our dividend remain our priorities, through these uncertain times. To finish, Diamondback is prepared to operate in a lower for longer oil price environment, and our cost structure will prove to be a differentiator through this downturn. Low interest expense, low leverage, industry-leading low-cash G&A, a full hedge book, strong midstream contracts, and the benefit of Viper and Rattler will allow Diamondback to operate effectively through these uncertain times. With these comments now complete, operator, please open the line for questions.

Thank you. Ladies and gentlemen, as a reminder to ask a question, you need to press star 1 on your telephone. To withdraw your question, please press the pound key. Please stand by while we compile the Q&A roster. And our first question comes from the line of Brian Singer with Goldman Sachs. Your line is now open.

Thank you. Good morning. Good morning, Brian. Good morning. Wanted to follow up on the comments there towards the end with regards to the use of cash and free cash flow. You talked about suspending the buyback. You've got the $400 million debt coming due. In a scenario next year, in a scenario where cash builds beyond that or where your free cash flow gets you above a $400 million cushion to pay down that debt, do you still hold cash back? for future debt coming due, or do you think about either bringing back the buyback considering variable dividends or distributions? How are you thinking about free cash flow and use of cash?

Well, certainly that's, you know, multiple quarters out as we look into next year, and all of those options are still available to us. You know, in terms of, you know, we announced the suspension of the share buyback program, but we also don't have a full, you know, an intention at the board level to hoard cash, and so you know, we will continue to be judicious in the way that we allocate excess cash, you know, as we highlighted, primarily through the form of our dividend program.

Great, thanks. My follow-up is with regards to cyclical versus secular benefits from the down cycle. You talked to cost reductions that you see here this year, and I wondered if you could speak to what you are kind of seeing as potential cyclical versus secular impacts, either on the productivity side and learnings there or on the cost side, what percent of the cost reductions. and if prices were to rebound?

Well, you know, if you just look at the Delaware Basin, you know, particularly I think we've taken over the last couple of quarters, we've taken $100 a foot out of the DC&E component, and those are permanent savings regardless of the cyclicality of our nature, of our business. You know, on the Midland Basin side, we've probably taken out $50 or $60, and again, a lot of those are also, you know, going to be made permanent. You know, we're We understand that our business partners on the service side are really in a bind and we do know that in the future when commodity prices begin to recover, that side of our business will have to repair their balance sheets and will require more consideration from other operators and that's the cyclical nature of that. We don't know when that's going to occur. We do think that the rate of change, you know, going forward just from a planning perspective, the rate of change is, you know, is getting smaller relative to where it was, you know, the last time we went through this in 15 and 16. But it's still our organization's intent to find those elements that will survive past the cyclical nature and actually make them permanent in the way that we go about prosecuting our development plans. So what percent is a lot harder to predict. It's smaller today than when you likely asked me that at 15 and 16. But, you know, we're still trying every day to identify and make permanent those savings. Okay, thank you.

Thank you. And our next question comes from the line of Derek Whitfield with 54. Your line is now open. Thanks. Good morning, all. Good morning.

Perhaps for Travis or Case, with regard to your 2020 outlook, I certainly appreciate the challenges of providing quarterly guidance in the current environment. Assuming the capital plan outline, is it reasonable to assume the previous exit rate guidance probably remains in place, less relatively small timing effects associated with returning curtail production back online?

Yeah, Derek, thank you. That's fair. You know, I think we're sticking to that exit rate guidance, you know, getting back to work in the back half of the year. You know, I think if, you know, first of all, curtailed volumes need to come back before we start completing new wells. And, you know, if curtailed volumes come back and then we start completing wells, you know, late in the summer or into the fall, then, you know, that number is certainly achievable. You know, if we continue to be curtailed or, you know, delay our return back to work, then we'll have to update the market, you know, as we have. now four times in the last month and a half, and give you the latest data that we're seeing.

Thanks. Very helpful. And you guys have been quite responsive in the environment, so I certainly appreciate that as well. With my second question, focusing on the voluntary curtailments that you discussed for May, are there any marketing limitations or technical considerations that would limit your ability to curtail volumes beyond that 10% to 15% level?

No, we're still very far away from any marketing commitments being triggered. You know, we produced a little over 250,000 gross barrels of oil a day in the first quarter. And our, you know, true take or pay commitments are about 125,000 barrels a day today. So we're still pretty far away from triggering any of those. And, you know, it's a secondary thought behind, you know, the cash operating costs of where we're curtailing and the, you know, the marketing commitments. contracts associated with the barrels that work with jailing.

Thanks, guys. Very well done in this challenging environment. Thank you.

Thank you. And our next question comes from the line of Gail Nicholson with Stevens. Your line is now open.

Good morning, everybody. Just looking at workovers, in a normal environment, do you know what percent of LOE workovers are comprised, and then how should we think about work over activity going forward, and do you have any thoughts if making an adjustment to work over could have an effect on future well productivity?

Yes, so Gail, typically we run between 20 and 25 work over routes, you know, on a daily basis, you know, just doing routine maintenance, and part of this curtailment effort that we're going through right now is that we reduce that number to less than 10, and maybe on some days even less than 5, and so as well as you know, fail or have problems, we are electing at least in the month of May not to go out and repair them. You know, as long as we don't have those type of failed wells shut in for a very long period of time, you know, months, I'm not worried about having to go back in and remediate those wells. Yes, there will be a cost, but that cost will be pushed out several months in that scenario, but the productivity shouldn't be impacted you know, unless we're talking about multiple, multiple months. But that's the way we're thinking about it now.

Okay, great. And then I really appreciate slide nine, the color, regarding the Midland-based contract. But I was just curious if you could talk about just how those pieces change regarding an MEH and a Brent contract on slide nine.

Yeah, Gail. So, you know, we wanted to show this slide to show our investors how we're thinking about curtailing volumes and You know, while, you know, we're exposed to flat price throughout the month, you know, the roll and the differentials had already been fixed, you know, going into May. You know, I will say for – it's contract dependent. So, you know, I'll only speak for Diamondback contracts. But, you know, a majority of our Brent-based contracts have a Brent roll component. So the Brent roll, because it's been in less contango than WTI, you know, will be a significantly smaller number.

Okay, great. Thank you.

Thank you, Jeff. Thank you. Thank you. And our next question comes from the line of Neil Dingman with Sunshine. Your line is now open.

Well, I hope you all are doing well. My first question centers on really your three-stream production growth and specifically how you all are viewing the timing and rate of growth for each of the three streams to ramp after your D&C is suspended and production is curtailed. Or, you know, maybe if I ask another way, how do you view production? So I know you've got the guide out there, but how do you view the near-term future oil versus natural gas growth?

Yeah, you know, I mean, no question, you know, with the production stream declining overall, you know, oil is going to decline faster than your BOEs. And I think we framed our, you know, oil production base decline at, you know, in the mid-30s with our BOE base decline in the low-30s percentages. So, you know, I'm hopeful that, you know, if we do get back to work, we're going to try to combat that decline, you know, some high oil percentage midland basin activity. But, you know, given the uncertainty today, I think overall, you know, those numbers that we put out there on base decline, you know, are still valid.

Got it. Great details. And then just my second question really focuses on cost. Travis, for you and Kay, you all continue to be certainly the cost leaders in the group when you speak to kind of $850-ish cash cost and I think what Midland well costs down to I think what, $700 or $600 per foot. I'm just wondering, you touched on this a little bit earlier, is there room to squeeze even more out of that or how do you all view just sort of these margins going forward given how low your costs are already down to?

Yeah, I think I answered it a little bit on the previous question about the rate of change and cost is certainly a lot smaller now than it was in 15 and 16 when we went through this cycle. You know, look, there's two ways to work on that. There's things like I emphasized that we can make permanent, those things live on forever, and that's, you know, the way we complete these wells faster, get the TD faster, you know, those are all elements of, you know, making permanent cost savings. You know, whether our business partners on the service side continually offer concessions, Beyond this point, there's probably going to be some, but we do feel like the majority of those have been offered up in the month of April and May as the industry has recalibrated quicker than anything we've ever seen.

I think if you dig into the cash cross piece, we're going to try to keep LOE flattish. Production's coming down, so that's going to hurt LOE a little bit. GNA is still going to stay best in class, and You know, the other pieces of cash costs on the tax piece, given that your percent of revenue continues to go down, that should come down a little bit. But, you know, we're fighting for pennies and nickels here.

And, you know, Neil, we've got a lot of information in our deck, you know, where we're talking about costs and, you know, improvements quarter over quarter. And I think it's important to recognize that one of the reasons that we try to answer the questions with as much detail as we can and and why as Case pointed out that we've updated the market four times in the last month and a half. It's because when times are uncertain and our investors that own the company have questions, transparency is more important than ever. So, you know, that's why we, you know, even though we might have had a free pass pulling guidance, it's just not part of our culture of transparency. You know, we're going to tell you everything we can within the rules of financial disclosure so that you can make the best investment decisions that you can. And the only way that we can do that is to be very, very transparent. And so whether it's in our deck or in our prepared remarks or in the Q&A, that transparency is one of the core tenets of DynaVac Energy, and we intend to follow that through these uncertain times and into the future.

I appreciate all the details, Travis. It certainly helps. Thanks, guys.

You bet. Thanks, Neil.

Thank you. And our next question comes from the line of Scott Breber with Citigroup. Your line is now open.

Yes, good morning.

Good morning, Scott.

So before the downturn, there was the expectation that your well productivity on average would improve over the course of 2020 as your HPP drilling fell even further and you shifted rigs. Now you're focusing obviously on best well economics, which includes not only productivity, but also obviously well cost and your minerals position and infrastructure needs. But can you provide some color on the productivity trend on a go-forward basis from here? Should it improve as previously expected in any color in order of magnitude?

Well, there's two ways to look at well productivity. It's, you know, if you're completing the same well, you know, one month versus next. Does that productivity improve in the current month versus the prior month? And there's also a way that productivity looks better on the macro sense because you're shifting the mix of projects that you're doing. And so most of what we were focusing on in our earlier communication was highlighting the shift from, you know, the Delaware Basin more towards the Midland Basin where we had, you know, mineral ownerships within our sub viper and then also not having to spend any, you know, or limited infrastructure dollars. So, you know, we're still going to see that effect, you know, through the course of this year as our program migrates more on the elevation side. And as I've answered now a couple of times, I still think there's room to see, you know, changes that we're making due to doing things better than we've done in the past. And those are the things that live on. Those are the ones we make improvements.

Got it. Appreciate the thought. That's it for me. I'll turn it back. Thank you.

And, Derek, let me just add, you know, when you think about where the service sector is, you know, I certainly don't intend to be a spokesperson for the service sector. I don't understand their financials like they do. And so, really, whether or not they continue to reduce costs, and it's to the benefit, at least near term, to Diamondback shareholders, you know, those are really questions that are best asked and answered on that side. What I'm leaning into our organization for is how can we do things better every day, regardless of the cyclical nature of what our business partners on the service side do.

Appreciate it.

Thank you. And our next question comes from the line of Scott Handel with RBC Capital Markets. Your line is now open.

Yeah, thanks. Thanks for all the calls so far. I'm the doctor. It was a pretty interesting comment that you guys would be carrying in the you know, 100 ducks into 2021, can you give a sense of, was that an intentional process through 2020, given, you know, the cost structure coming down enough? Was it somewhat where your rig contracts were and just didn't want to complete the wells, or you just wanted some, you know, dry powder of wells to, you know, reactivate when you could? So can you give us a sense of, you know, how you balance that, you know, that activity and decision through this year?

Yeah, it's really got a combination of all three of those. I mean, we definitely have rig contracts and every dollar counts, and while those rig counts, you know, wind off this year, we didn't want to pay early termination fees. But also, when you think about 2021 and you're carrying in a large number of ducks, you know, we're really covered off on both the bull case and the bear case. You know, in the bull case, you know, we'll have a bunch of really high-quality ducks, that we can bring on to production quickly in 2021 if we get paid for the commodity we produce. On the bear case, if it gets bad, you know, well, then we probably won't drill, you know, many, if any, wells at all in 2021. And whatever, you know, volume maintenance that we feel like we can get paid for, we can do that just by completing these extremely high rate of return on a cost-forward basis ducts.

My follow-up is going to be on the decisions as you look into that bull case. What are really the triggers that make you think about that bull case? Also, just really quickly, how much of an impact on your 2021 maintenance capital do those ducks have?

We've never tried to predict oil price and what a bull case looks like in 2021. I'm not even saying that that's necessarily going to occur. What we're trying to do is rather than predict, we're trying to cover off both extremes of what likely outcomes could be next year. And in terms of the duck impact on maintenance capex.

Yeah, Scott, we came out with a number about a month ago saying we could keep exit rate production flat year over year in 2021 with about 25% less capital than 2020. You know, I think that number still stands, and that probably assumes, you know, you're drawing down 40 or 50 ducks. You know, I think, you know, our base case today, if you had to, you know, if you had to ask us, is somewhere in the range of three to five completion crews. And, you know, the rule of thumb that we have is, you know, 10 working ducks for each completion crew. So we're going to have about 100 extra ducks at the year-end 2021 to, you know, have options with.

Yeah, and just to be more specific, I wasn't asking, I guess, in particular, you know, what you all think about the bull case of next year, just what price signal, like what price does it have to be to start, you know, thinking about getting a little bit more active and, you know, dipping into those ducks?

Well, let's look at where we are today, right? The first thing we'd have to do is, you know, bring deferred production back on. And then, you know, to talk about increased activities, you know, Again, there's a lot of factors that weigh into that, but you've got to have prices in the high 20s or low 30s, you know, before we, you know, kind of, you know, signal going back to work in an aggressive, you know, or even in a non-aggressive way. But again, we're going to take all of these things into consideration before we come out and update the market on what our activity plans are back after this year or in the next year as well.

Okay, fair enough. Thank you.

Thank you. And our next question comes from the line of David Dekelbaum with Cowan. Your line is now open.

Morning, guys. Thanks for your time today.

You bet, David.

I was just hoping maybe you could add a little bit more color on the theoretical 21 maintenance program. How many wells did that envision you being able to or needing to turn in line to hold that current exit guide flat in 21?

Probably about 150, David, plus or minus 10 or 15 wells on each side of that. Just based on the wells we're drilling today and what gets completed, we're going to be pretty heavy in Midland Basin, probably 70-30 Midland Basin and 75-25 Midland Basin in areas where we have high mineral interest and very little capital required on the infrastructure side.

I appreciate that. And then I guess... I just wanted to go back to the curtailments. One, could you update us just on – I know you kind of hedged your comments and said if we need to do something in June, then obviously guidance changes. What are your thoughts on June right now? How do you see the market shaping up and balancing? I know these curtailments are economically driven, and the price signals have improved a bit for June. What are you seeing on the logistics side and the embassies side, and how do you see this shaping up with – You know, granted, we're several weeks away, but how is it looking currently?

Well, you know, it's looking a little better for June, to be honest. You know, with the dips in the roll, you know, being significantly, you know, on the roll side, significantly less negative. On the dip side, you know, being Midland trading at a premium recently to WTI. And on top of that, WTL trading at a premium to WTI. So, you know, I never thought $22 low would be exciting, but, you know, here we are. you know, looking at our cash costs for June. And I think, you know, as we sit today, you know, we have nominations due in two weeks. As we sit today, it certainly looks better for the June month from a contract perspective than it did in May.

Yeah, here's the 22. If I could just lob in one quick one. Just thinking about the logistics of the curtailed volumes that you have now, I guess about 2,500 producing wells in Midlands and another 500-plus in the Delaware area. What percentage overall of those wells are being curtailed right now? Or I guess how many wells can you say are being curtailed?

Yeah, just about 500 total. And I would say, you know, over two-thirds of those are in the Delaware. And so what we've really focused on is – and we've really focused on the term curtail because we're not shutting these wells in and having to spend dollars to shut wells in. You know, we're trying to, you know, limit the cash outflow. and, you know, really just curtail producing wells, you know, through a lower level than where they were in April and March.

Thanks for the call, guys.

You bet. Thanks, Dave.

Thank you. And our next question comes from the line of Jeff Grant with Northern Capital Markets. Your line is now open.

Good morning, guys. Hey, Jeff. Good morning. Good morning. I was curious how you guys maybe kind of philosophical question, you know, pricing environment both on the commodity and, you know, well costs have obviously changed quite a bit over the last several months. Are you guys internally discussing maybe reevaluating well spacing or completion techniques as far as what an optimal design could be and, you know, with today's service costs and oil price environment?

Yeah, those are certainly things that we're examining. But one thing that, you know, I've been pleased with is that Our spacing assumptions that have been validated now for almost five years really haven't ever changed. We've never been part of that drill wells too closely or stacking too tightly together. The rule of thumb has always been the higher the oil price, the closer spaced you can put your wells because you can capitalize on acceleration and the lower priced oil is, the wider you should spread out. We've followed that, but we've been pleased that our spacing assumptions seem to have struck the right balance now for multiple years, and a lot of technical review with our reserve auditors have validated that, so we've never really tightened them up, and in some instances, maybe even in Delaware and some of the new developed zones, we might have slightly increased the well spacing, but in a general sense, we've been very conservative on how we count locations and how we how we develop these reservoirs. When you look at the completion side, Jeff, we are always trying to do everything we can to extract the most hydrocarbons from these rocks. Stimulated rock volume near well boards is the key. I can tell you the scientists, the engineering and geology scientists that we have, they are always tweaking with that. While we can look at spacing When we actually get down to completing the well, you know, that's just a constant work in progress, and it's always evolving. All right. And that will never change. I can promise you.

Understood. And then kind of more of a housekeeping one, if I may. The ducts that you guys are kind of building in real time here, and we've talked about a couple times in the call already, are those weighted to maybe certain operating areas or Midland versus Delaware focused?

Yeah, you know, it's really about 70-30 Midland, Delaware. You know, most of our rigs are moving towards the Midland Basin where we have high mineral interest and, you know, setting ourselves up for the most capital efficient return to work possible.

Got it. Thank you.

Thank you. Another question comes from the line of Asit Singh with Bank of America. Your line is now open.

Thanks. Good morning. I have one for Case, one for Travis. Case, on counterparties and flow assurance, thanks for all the detail update in the slide deck. My question is, there have been some reports on the seaborne market getting backed up. Can you talk directly about the condition of the export market perhaps into the next couple of months? And in terms of take or pay liabilities, could you update us in theory on what happens if there's a physical flow bottleneck in any of these pipes?

Yes. So, you know, I don't know all the details about the seaborne market, you know, but I do know it's more liquid than, you know, what we've seen in pushing the last few weeks. So, you're certainly starting to see spreads widen and incentivize, you know, barrels to get on the water. Now, tanker rates certainly spiked a little bit, which would impact our realizations, but they've come back down a little bit here. But, you know, overall, the whole point of the, you know, our marketing arrangements is to provide insurance in terms of in times of uncertainty, which we're in right now, and you know, being able to call only four marketers and know that all our barrels are going to move is something that allows us to sleep a little better at night. You know, on the take-your-pay piece, you know, 125,000 barrels a day is take-your-pay from a sales perspective as well as from a pipeline perspective. You know, should the sales piece, you know, declare force majeure, which would be the only instance where those barrels don't move, you know, our total pipeline commitments right now in Grey Oak and Epic is about, you know, $20 million per pipe per year if we didn't send one barrel down each pipe.

Thanks, Case. Travis, on a potential restruct scenario, how quickly could you restart operations? What are the price signals and what are some of the other broader considerations would you consider before adding a rig on a completion crew?

Well, it should always be driven by economics, right? The first thing we would do is obviously get our curtailed volumes back into the production equation. Following that, we're going to look at economics about what the service sector is going to charge to come back to work, and then we'll balance that against what our expectations are for the forward curve and make an economic decision on that. I think I alluded to some form of start in the high 20s or low 30s, but really, You know, if you flash all the way out there to what our world used to look like in growth, you know, that's back to prices that you saw last year. So, you know, I think this, you know, as we evolve as an industry into this new oil order, you know, I think it's going to look a lot different than what we've historically been accustomed to.

Appreciate it. Thanks, Craig.

Thank you. And our next question comes from the line of Charles Meade with Jason Rice. Your line is now open.

Good morning, Travis, to you and your whole team. Thank you, Charles. Travis, you anticipated, I guess, my question in your response to your earlier one. I wanted to – I get the point that you guys are prepared for a lower – for a longer scenario. But also, it seems from the outside looking in that you guys are more prepared more on your front foot for a V-shaped recovery. In other words, you know, you're better positioned than others in the industry to go back to work hard in the back half of the area. Is that an accurate read, do you think? And how would you elaborate on that?

Yeah, well, first, we're certainly not in the prediction of what a recovery is going to look like, V-shaped or U-shaped or whatever. What we're trying to do is demonstrate flexibility to our investors, that whether it's lower for longer, we're prepared for that with our financial strength, or whether the market signals that it's time to go back to work, we're also prepared for that. But again, back to my transparency comment, you know, in these uncertain times, whichever scenario plays out, you can count on us, you know, stepping forward and letting our investors know exactly what we're thinking about the business and the strategic rationale behind the decisions that we make.

Got it. And then maybe following up a little bit on that activity, I get that you're not completing wells right now, but you guys are still going to run a completion crew for part of the quarter. And I know you said that's for lease retention or lease obligation consideration. I'm curious. I imagine there have to have been other options you evaluated about going back to the mineral owners and maybe offering a rental facility or some other thing. Are there other considerations that are going on that are, you know, leading you to complete, you know, 15 or 20 wells or so in 2Q rather than do some of those other lease obligation options?

Yeah, Charles, you know, a lot of those wells, you know, probably already in progress, you know, heading into the quarter, so you can't have that discussion, you know, mid-completion. You know, we are, you know, working with our mineral owners, and they have been pretty, you know, pretty easy to work with through this, given where flat price is. You know, so if we can push out whatever we can whenever we can, we're trying to do that. You know, it's hard to, in a 1,280-acre unit, you know, get in touch with 40 mineral owners in a month. But, you know, we have been working diligently to extend leases and extend completion dates.

Yeah, Charles, just to add to that, the complexity is, you know, unless you're actually inside you know, it's hard to communicate. But I'll tell you, our land organization, you know, and our land professionals, you know, they are engaged, you know, almost they're engaged every day in what feels like a knife fight to work on lease terms to avoid, you know, having to drill or complete a well and, you know, when we're not getting paid for the commodities. So, you know, as Case indicated, you know, a lot of our mineral owners, you know, understand the business and are trying to make concessions but also it's very difficult at times to get everyone on the same page and all it takes is one person to say no and then your hand is forced so really proud of our land organization and the work they're doing to get us to the point where we're only running one completion crew to honor minimal obligations this quarter.

Thank you for the detail.

Thanks Charles.

Thank you. Thank you. And our next question comes from the line of Richard Telles with Capital One Securities. Your line is now open.

Hey, thanks. Good morning, everyone. Travis, generally, how much runway do you have as far as well inventory to continue on the current path where you're drilling the areas with higher NRIs and lower infrastructure needs?

Yeah, Richard, you know, I think we, you know, we try to be as transparent as possible and show, you know, what our gross and net inventory is on slide 13 and slide 14 in the deck. And, you know, we update that every year. You know, I think, you know, one of the benefits of slowing down is you're not burning through as much inventory that quickly. You know, so I think, you know, with us needing to complete 150, 160 wells, keep production flat, you know, and 75% of it in the Midland Basin, you got a pretty long runway of high quality inventory, you know, to survive, you know, a lower for longer environment.

Yeah, we've got over 12,000 gross locations still in front of us, Richard. And, you know, with this slowdown in activity or stoppage in activity, exactly as Kay said, we're actually extending our inventory runway as a result of completing those wells on the name of license.

Okay. Thank you. And secondly, You know, any plans to resume testing of the limelight acreage in the second half of the year, or does that just need to wait for substantially higher oil prices?

Yeah, it probably needs to wait. You know, we're having discussions with the mineral owners right now on extending or delaying, you know, our next test.

Okay. That's all from me. Thank you.

Thank you.

Thank you.

And our next question comes from the line of Jason Wangler with Imperial Capital. Your line is now open.

Hey, good morning. Just had one, and obviously it's something we've talked a lot about in the past, but it's probably weird now. But, you know, as far as you've got plenty of inventory certainly, but you're in a much better position than so many others around you. As you think about this playing out and maybe at some point getting more aggressive, are you seeing anything that's maybe interesting from the M&A side, or maybe how do you just kind of see that playing out as we kind of go forward in this tough environment?

Yeah, hey, Jason, this is all about, you know, demonstrating our financial strength and getting to the other side of the recovery. When we're there, when the market's signaling it's there, I think that question, you know, has more validity. But right now, you know, it's doing what we're doing, which is, you know, maximizing cash flow and preserving liquidity.

Fair enough. I appreciate it. Thank you. Thank you. And our last question comes from the line of Michael Hall with Heigenen Energy. The line is now open.

Thanks. Good morning. Appreciate the time. A lot has been addressed. But, you know, one that's kind of been touched on a little bit but wanted to follow up on is just in the context of signaling or what sort of price signals are required to get back to kind of quarter-on-quarter growth or move beyond that maintenance capital cycle. program in 21 number one what might those prices theoretically look like sounds like maybe last year's type of level but just wanted to confirm that and then number two maybe more philosophically like how are you thinking about the combination of growth and payout on a longer term basis is the growth side of that combination structurally lower than it was a year ago let's say after what we've just been through or Is it really not affected and it will really just be a function of what prices and returns look like whenever that time comes?

I think our industry is evolving perhaps at a more rapid pace than it ever has. I mean, we were making changes at the end of last year, you know, as an industry, you know, of a slower growth and a greater return model, and that got kicked into hyperspeed in March of this year, you know. So, you know, this new oil order as we look ahead, you know, is going to have what feels like at least today, is going to feel like a lot lower growth and a more prescriptive way of returning, you know, investments or returning, you know, returns to our investors. And, you know, I think it's still going to evolve through the course of this year, but, you know, certainly under what the strip looks like, it's going to definitely be a lot lower growth profile. But, you know, we want to make sure we maintain the dividend and resume, you know, when you maximize their cash flow and, you know, and when appropriate, you know, the market signals, you know, have peer-leading growth and be able to accomplish all those at the same time.

Okay. I mean, is it fair to say at a 40 to 50 range, all those equal today, knowing that all those equal is a hard assumption to make, but, you know, that that's maybe roundabout the level that would signal getting back to a quarter-on-quarter growth profile?

Yeah, it's more than just an oil price. I think I said earlier that if you look at some of the prices that we got in 2019, you know, that certainly is a signal that you can, you know, get more, you know, get more aggressive on the growth. But I think we've got to be pretty careful in being too prescriptive on, you know, what exact price signal is going to look like before you get back to growth. Again, I just want to make sure we maintain our dividend, maximize our cash flow, and when it is time to grow, you know, Diamondback will have peer leading growth along with that dividend and maximize the cash flow.

Understood. I appreciate the call, Aaron.

Just to finish that thought, you know, I kind of went on a little earlier about, you know, transparency and I think it's important, again, to emphasize it here. You know, we're trying to communicate as transparent as we can the way that we see the future and you can count on us As the future gets clearer, you know, we're going to update the market. Like I said, we've done it four times in the last five weeks, and we're going to continue to be communicative, and we're going to continue to demonstrate one of the hallmarks of our corporate culture, which is transparency. And we'll let you know as these things evolve. Thank you.

And this does conclude today's question and answer session. I would now like to turn the call back to Travis Spice for closing remarks.

Sure. Thank you. Listen, before I close this morning, I wanted to share with you guys a final thought. We've all had what feels like an unreasonable amount of time to reflect over the last couple of months as we've worked remotely or sheltered in place. And when I've done that and looking back at the over 35 years I've had in the industry, there's been – several significant events that have stood out. You know, the Challenger spaceship disaster in 1986, the financial crisis of 2007 and 2008, of course, 9-11, and now we're embroiled in a worldwide pandemic caused by the coronavirus. But when I look back at those historical events that I participated in, during those times, there were really two defining attributes that I felt were demonstrated. The first is really the resiliency of the American people. Even in the face of human tragedy and financial tragedy, we found a way to move forward. And the second attribute, and I think it's important in today's environment, is hope. Hope that we would get through this and hope that our situation would get better. And so as we get this country back to work, Let's count on that resiliency once again. Let's also remind each other the importance of hope. Hope for ourselves, for our kids, and our grandkids that tomorrow will be better. Thank you for participating in today's call. Please reach out if you have any questions.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating, and you may now disconnect.