Diamondback Energy Inc (FANG) 2020 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Diamondback Energy First Quarter 2020 Earnings Conference Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions) And as a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Adam Lawlis, 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 Stice, CEO; and Case 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. 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, where the 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 2 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 unhedged oil realizations averaged 99% of WTI, our highest oil realization in almost 2 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 8 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're 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 DUCs. This is over 100 DUCs above what will be required as a standard working DUC inventory for a 3 to 5 completion crew 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 number, 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 2 months later in cash flow statement, while commodity price fluctuations are realized in the month in which they occur. As a result, our CapEx spend will be weighted towards 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.

Diamondback is curtailing gross operating production by 10% to 15% this month due to the uncertainty in the forward oil price contracts and the risk of low unhedged realized oil prices for the month. With differentials and roll 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 roll 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 to 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 curtailment 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 forward 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 one of 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 of liquidity and only have 1 term debt maturity due in the next 5 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.

(Operator Instructions) Our first question comes from Brian Singer with Goldman Sachs.

I 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 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 in multiple quarters out as we look into next year. And all of those options are still available to us. In terms of -- we announced the suspension of the share buyback program. But we also don't have a full -- an intention at the Board level to hoard cash. And so we will continue to be judicious in the way that we allocate excess cash as we highlighted primarily through the form of our dividend program.

Great. And then my follow-up is with regards to cyclical versus secular benefits from the down cycle. You've 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 you're achieving this year do you think would extend if prices were to rebound?

Well, if you just look at the Delaware Basin, 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. On the Midland Basin side, we've probably taken out 50 or 60. And again, a lot of those are also going to be made permanent. 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, we'll have to repair their balance sheets and will require more consideration from the operators. And that's the cyclical nature of that. But we don't know when that's going to occur. We do think that the rate of change going forward, just from a planning perspective, the rate of change is getting smaller relative to where it was 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 plan. So what percent is a lot harder to predict. It's smaller today than when you likely ask me that in '15 and '16. But we're still trying every day to identify and make permanent those savings.

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

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 outlined, is it reasonable to assume the previous exit rate guidance broadly remains in place less relatively small timing effects associated with returning curtail production back online?

Yes, Derrick. Thank you. That's fair. I think we're sticking to that exit rate guidance pending getting back to work in the back half of the year. I think if -- first of all, curtailed volumes need to come back before we start completing new wells. And if curtailed volumes come back and then we start completing wells late in the summer or into the fall, then that number is certainly achievable. We continue to be curtailed or delay our return back to work, and we'll have to update the market as we have now 4 times in the last 1.5 months and give you the latest data that we're seeing.

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. We produced a little over 250,000 gross barrels of oil a day in the first quarter, and our 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 it's a secondary thought behind the cash operating costs where we're curtailing and the marketing contracts associated with the barrels that we're curtailing.

It's very well done in this challenging environment.

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

Just looking at workovers. In a normal environment, do you know what percent of LOE workover is comprised? And then how should we think about workover activity going forward? And do you have any thoughts if making an adjustment for workovers could have an effect on future well productivity?

Yes. So Gail, typically, it'd be around between 20 and 25 workover rigs on a daily basis, just doing routine maintenance. And part of this curtailment effort that we're going through right now is that we reduced that number to less than 10, and maybe on some days, even less than 5. And so as wells fail or have problems, we are electing, at least in the month of May, not to go out and repair them. As long as we don't have those type of failed wells shut in for a very long period of time, 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 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 9, 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 9.

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

And our next question comes from the line of Neal Dingmann with SunTrust.

My first question centers on really your 3-stream production growth, and specifically, how you are viewing the timing and rate of growth for each of the 3 streams to ramp after your D&C is suspended and the production is curtailed? Or maybe if I ask in another way, how do you view sort of -- I know you've got the guide out there, but how do you view the near-term future oil versus natural gas growth?

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

Got it. Great details. And then just my second question really focuses on cost. Travis, for you and Case, 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 cost down to, I think, what, $700 or $600-ish 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 what -- how low your costs are already down to?

Yes. I think I answered it a little bit on the previous question about the rate of change in cost is certainly a lot smaller now than it was in '15 and '16 when we went through the cycle. Look, there's 2 ways to work on that. There's things like I emphasize that we can make permanent. Those things live on forever, and that's the way we complete these wells faster, get to TD faster. Those are all elements of making permanent cost savings. Whether our business partners on the service side continue to 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 as you dig into the cash cost piece, we're going to try to keep LOE flattish, production is coming down, so that's going to hurt LOE a little bit. G&A is still going to stay best-in-class. And 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 we're fighting for pennies and nickels here.

And Neal, we've got a lot of information in our deck where we're talking about cost and 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 why, as Case pointed out, that we've updated the market 4 times in the last 1.5 months, it's because when times are uncertain and our investors that own the company have questions, transparency is more important than ever. So that's why we -- even though we might have had a free pass full in guidance, it's just not part of our culture of transparency. 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 Diamondback Energy, and we intend to follow that through these uncertain times and into the future.

And our next question comes from the line of Scott Gruber with Citigroup.

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

Well, there's 2 ways to look at well productivity. It's -- if you're completing the same well 1 month versus next, is 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 the Delaware Basin more towards the Midland Basin, where we had mineral ownerships within the -- our sub Viper and then also not having to spend many -- or limited infrastructure dollars. So we're still going to see that effect through the course of this year as our program migrates more on the Midland Basin side. And as I've answered now a couple of times, I still think there's room to see 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 permanent.

And Derrick, let me just add. When you think about where the service sector is, 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 cost, and it's to the benefit, at least near term to Diamondback shareholders, 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.

And our next question comes from the line of Scott Hanold with RBC Capital Markets.

On the DUCs, it was a pretty interesting comment that you guys would be carrying in 100 DUCs into 2021. Can you give a sense of -- was that an intentional process through 2020, given 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 dry powder of wells to reactivate when you could? So can you give us a sense of how you balance that activity and decision through this year?

Yes. It's really -- it's got a combination of all 3 of those. I mean we definitely have rig contracts, and every dollar counts. And while those rig accounts 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 DUCs, we're really covered off on both the bull case and the bear case. In the bull case, we'll have a bunch of really high-quality DUCs 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, well then we probably won't drill many, if any wells at all, in 2021. And whatever 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, DUCs.

So -- and my follow-up is going to be on the decisions as you look into that bull case, like what are the -- really the triggers that make you think about that bull case? And also, just really quickly, what do those DUCS -- how much of an impact on your 2021 maintenance capital do those DUCs have?

Well, we've never tried to predict oil price in 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 what likely outcomes could be next year. And in terms of the DUC impact on maintenance CapEx?

Yes. 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. I think that number still stands, and that probably assumes you're drawing down 40 or 50 DUCs. I think our base case today, if you had to ask us, is somewhere in the range of 3 to 5 completion crews. And the rule of thumb that we have is 10 working DUCs for each completion period. So we're going to have about 100 extra DUCs at year-end 2021 to have options with.

Yes. And just to be more specific, I wasn't asking, I guess, in particular, 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 thinking about getting a little bit more active and dipping into those DUCs?

Well, let's look at where we are today. Right? The first thing we'd have to do is bring deferred production back on. And then to talk about increased activity, 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 before we kind of signal going back to work in an aggressive or even in a nonaggressive 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 half of this year or into next year as well.

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

I'm just hoping maybe you could just 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 the current exit guide flat in '21?

It's 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 work gets completed. We're going to be pretty heavy in Midland Basin, probably 70-30 Midland Basin or 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. The price signals have improved a bit for June. What are you seeing on the logistics side and the in-basin side? And how do you see this shaping up with -- granted we're several weeks away, but how is it looking currently?

No. It's looking a little better for June, to be honest. If the dips and the roll being significantly -- on the roll side significantly less negative on the dip side being Midland trading at a premium recently to WTI. And on top of that, WTL trading at a premium to WTI. So I never thought $22 oil would be exciting, but here we are looking at our cash costs for June. And I think as we sit today, we have nominations due in 2 weeks. As we sit today, it certainly looks better for the June month from a contract perspective than it did in May.

Yes. So here's to $22. If I could just lob in 1 quick one. Just thinking about the logistics of the curtailed volumes that you have now. I guess about 2,500 [pursuing] wells in Midlands, another 500-plus in the Delaware. What percentage overall of those wells are being curtailed right now? Or I guess how many wells can you say are being curtailed?

Yes. Just about 500 total. And I would say, over 2/3 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. We're trying to limit the cash outflow and really just curtail producing wells to a lower level than where they were in April and March.

And our next question comes from the line of Jeff Grampp with Northern Capital Markets.

I was curious how you guys -- maybe kind of philosophical question. Pricing environment, both on the commodity and 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 in with -- today's service costs and oil price environment?

Yes. Those are certainly things that we're examining. But one thing that I've been pleased with is that our spacing assumptions have been validated now for almost 5 years, really haven't ever changed. We've never been part of that drill wells too closely or stacking too tightly together. So the rule of thumb has always been the higher the oil price, the closer space that you could put your wells because you can capitalize on acceleration, and the lower-priced oil is the wider you should spread out. But we've been -- we 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 on the 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 develop these reservoirs. And 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 wellbore is the key. And I can tell you, the scientists, the engineering and the geology scientists that we have, they're always tweaking with that. So while we can look at spacing when we actually get down and completing the well, that's just a constant work in progress, and it's always evolving. And that will never change, I can promise you.

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

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

And our next question comes from the line of Asit Sen with Bank of America.

I have 1 for Case, 1 for Travis. Case, on counterparties and flow assurance, thanks for all the detailed update in the slide deck. My question is there have been some reports on the seaborne market getting back 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 is a physical flow bottleneck in any of these pipes?

Yes. So I don't know all the details about the seaborne market, but I do know it's more liquid than what we've seen in Cushing in the last few weeks. So you're certainly starting to see spreads widen and incentivize barrels to get on the water. Now tanker rates certainly spiked a little bit, which would impact our realizations, but they come back down a little bit here. But overall, the whole point of the -- our marketing arrangement is to provide insurance in terms of -- in times of uncertainty, which we're in right now and being able to call only 4 marketers and know that all our barrels are going to move is something that allows us to sleep a little better at night. On the take-or-pay piece, 125,000 barrels a day is take-or-pay from a sales perspective as well as from a pipeline perspective. Should the sales piece declare force majeure, which would be the only instance where those barrels don't move, our total pipeline commitments right now on Gray Oak and Epic is about $20 million per pipe per year if we didn't send 1 barrel down each pipe.

Thanks, Case. Travis, on a potential restart 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? And so the first thing we would do is obviously get our curtailed volumes back into the production equation. And then 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, if you flash all the way out there to what our world used to look like in growth, that's back to prices that you saw last year. So I think this -- as we evolve as an industry into this new order, I think it's going to look a lot different than what we've historically accustomed -- we've been accustomed to.

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

Travis, you anticipated -- I guess, my question in your response to an earlier one, I wanted to -- I get the point that you guys are prepared for a lower-for-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're better positioned than others in the industry to go back to work hard in the back half of the year. Is that an accurate read, do you think? And how would you elaborate on that?

Yes. Well, first, we're certainly not in the prediction of what a recovery is going to look like V shape or U shape or whatever. But 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, on these uncertain times, whichever scenario plays out, you can count on us 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 or some other thing. Are there other considerations that are going on that are leading you to complete 15 or 20 wells or so in 2Q rather than do some of those other lease obligation options?

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

Yes. Charles, just to add to that, the complexity is -- unless you're actually inside, it's hard to communicate. But I'll tell you, our land organization and our land professionals, they are engaged almost -- they're engaged every day in what feels like a knife fight to work on lease terms to avoid having to drill or complete a well when we're not getting paid for the commodity. So as Case indicated, a lot of our mineral owners 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 1 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 1 completion crew to honor minimal obligations this quarter.

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

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?

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

Yes. We've got over 12,000 gross locations still in front of us, Richard. And with this slowdown in activity or stoppage in activity, exactly as Case said, we're actually extending our inventory runway as a result of completing those wells on an annual basis.

Okay. And secondly, 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?

Yes. It probably needs to wait. We're having discussions with the mineral owners right now on extending or delaying our next test.

And our next question comes from the line of Jason Wangler with Imperial Capital.

Just had one, and obviously, it's something we've talked a lot about in the past, but it's probably weird now. But as far as -- you've got plenty of inventory, certainly, but you're not -- 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?

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

And our last question comes from the line of Michael Hall with Heikkinen Energy.

I appreciate the time. A lot have been addressed, but 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 program in '21. Number one, what might those prices theoretically look like? It sounds like maybe last year's type of level, just wanted to confirm that. And then number two, maybe more philosophically, like how are you thinking about the combination of growth and payout for -- 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 as an industry of a slower growth and a greater return model. And that got kicked into hyperspeed in March of this year. And so this new oil order, as we look ahead, is going to have what feels like, at least today, is going to feel like a lot lower growth in a more prescriptive way of returning investments or returning returns to our investors. And I think it's still going to evolve through the course of this year. But certainly under what the strip looks like, it's going to definitely be a lot lower growth profile. But we want to make sure we maintain a dividend and resume -- maximize our cash flow. And when appropriate, the market signals have peer-leading growth to 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 else equal today, knowing that all else equal is a hard assumption to make, but that's just maybe around about the level that would signal getting back to a quarter-on-quarter growth profile?

Yes. 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, that's certainly a signal that you can get more aggressive on the growth. But I think we've got to be pretty careful in being too prescriptive on what exact price signals 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, Diamondback will have peer-leading growth along with that dividend and maximize cash flow.

Just to finish that thought. I kind of went on a little earlier about transparency, and I think it's important again to emphasize it here. 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 clear, we're going to update the market. Like I said, we've done it 4 times in the last 5 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.

And this does conclude today's question-and-answer session. I would now like to turn the call back to Travis Stice 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: the challenger spaceship disaster in 1986, the financial crisis of 2007 and 2008, of course, 9/11, and now we're enrolled 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 2 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.