Diamondback Energy Inc (FANG) — Q1 2020 Earnings Call Transcript

Thank you, Kurt. 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 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 will 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 would 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. Our perseverance is evident in the decisive action we have taken to preserve our strength in this cycle. Our organization has been working from home for almost two months. And I can honestly say that 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 will 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 organization averaged 99% of WCI, our highest oil realization in almost two years. We returned 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 supporting operations in the fourth quarter of 2019. We maintained continuous operations with over 20 rigs and eight completion crews running through most of the first quarter. Capital spend was 709 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 in 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 eight—down over 60% from the beginning of the year. We also plan to enter the fourth quarter running seven 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 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, we will start to see our reduction activity benefit our cash flow 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 the 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 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. Diamondback is curtailing gross operating production by about 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 mill. With differentials already set heading into the month at over $10 off the 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 in both protection. Therefore, we can monetize in-the-money hedges without materially impacting the cash flow when production is curtailed. In 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. 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. We are trying to stay flexible on how many completion crews we bring back to work in the second half of the year, and in which month those crews get back to work. We 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 preserving as much liquidity as possible. We ended the first quarter with $1.9 billion of liquidity and have only 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 the suspension of our buyback program, we expect to maximize liquidity and retain cash to pay down debt. Our dividends remain our primary return of capital for our equity holders, and the Board of Directors has decided to maintain the dividends based on the current board 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 us to operate effectively through these uncertain times. With these comments now complete. Operator, please open the line for questions.

Thank you. Good morning. I wanted to follow-up on the comment there towards the end regarding the use of cash and free cash flow. You talked about suspending the buyback, you have the $400 million debt coming due 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 the use of cash?

Well, certainly that is 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 our share buyback program, but we also don't have a full intention at the board level to hoard cash. 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, thanks. And then my follow-up is regarding cyclical versus secular benefits from the downside goal; you talked about cost production that you see here this year. I wondered if you could speak to what you are seeing as potential cyclical versus secular impacts, either on the productivity side and learning there or on the cost side. What percent of the cost reductions you are achieving this year do you think would extend if prices were to rebound?

Well, if we just look at the Delaware basin, and particularly over the last couple of quarters, we have taken $100 a foot out of the DC and E-components. And those are permanent savings regardless of the cyclicality of our business. On the Midland basin side, we have probably taken out 50 or 60, and again, a lot of those are going to be permanent as well. We understand that our business partners on the service side are really in a bind. 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 we will require more consideration from other operators, and that is the cyclical nature there. But we don't know when that is 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 2015 and 2016. But it is still our organization's intent to identify those elements that will survive past the cyclical nature and actually make them permanent in the way that we go about executing our development plan. So what percent, is a lot harder to predict? It is smaller today than when you likely ask me that in 2015 and 2016, but we are still trying every day to identify and make permanent those savings.

Great. Thank you.

Thanks. Good morning all.

Good morning.

Perhaps for Travis or Kaes, regarding 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 broadly remains in place, with relatively small timing effects associated with returning curtailed production back online?

Yes. Derrick, thank you. That is fair. I think we are sticking to that exit rate guidance, pending getting back to work in the back half of the year. I think if curtailed volumes 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 will continue to be curtailed or delay our return back to work and will keep the market updated, as we have four times in the last month and a half, and give you the latest data that we are seeing.

Thanks, very helpful, and you guys have been quite responsive in the environment. So 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 compare volumes beyond that 10% to 15% level?

No. We are 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 take-or-pay commitments are about 125,000 barrels a day today. So, we are still pretty far away from triggering anything of those. And the secondary thought behind the cash operating costs was where we are curtailing in the marketing contracts associated with the barrels that we are curtailing.

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

Thank you.

Good morning everybody. Just looking at work over. In normal environments, do you know what percent of LOE workover comprise? And then how should we think about workover activity going forward? And do you have any thoughts if making an adjustment to workover will have an effect on future well productivity?

Yes. So Gail, typically we are around 20, 25 workover hits on a daily basis, just doing routine maintenance, and part of this curtailment effect that we are going through right now is that we reduced that number to less than 10, maybe on some days, even less than five. So as wells fail or have problems, we are electing, at least in the month of May now to go out and repair them. As long as we don't have those types 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. Yet, there will be a cost, but that cost will be pushed out several months in that scenario, but productivity shouldn't be impacted. And as we are talking about multiple, multiple months. But that is where we are thinking about it now.

Okay, great. And then I really appreciate Slide 9 the color regarding the Midland based contracts. But I'm 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 the slide to show investors how we are thinking about curtailing volumes. While we are supposed to put flat price throughout the month, the role and the differentials had already been fixed going into May. I will say it’s contract dependent, so, all we speak for are Diamondback contracts, but the majority of our Brent based contracts have a Brent role component, so it is a Brent role because it has been less contained than WTI will be a significantly smaller number.

Okay. Great. Thank you.

Thank you, Gail.

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

Yes Neal. 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 are going to try to combat that decline with more Midland basin activity. But given the uncertainty today, I think overall, those numbers that we have out there on base decline are still valid.

Yes. That is great details. And then just my second question really focuses on cost. You know Travis for you in case you'll continue to be certainly the cost leaders in the group when you speak to kind of $850 as cash cost, and I think what Midland well cost down, I think what is $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 like how well you are cost already down to?

Yes. I think I answered it a little bit on the previous question about the rate of change, and the cost is certainly a lot smaller now than it was in 2015 and 2016 when we went through the cycle. Look, there are two ways to work on that. There are things, like I emphasized that we can make permanent those things moving forward, and that is loading completely as well as faster to get the 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 is probably going to be some, but we do feel like the majority of those have been offered up in the month of April and in May as the industry has recalibrated quicker than anything we have ever seen.

Again I think if you dig into the cash cost fees, we are going to try to keep LOE flattish, productions coming down so that is going to hurt LOE a little bit, G&A is still going to stay best-in-class, and the other pieces of cash cost some on the tax piece given percent of revenue, continues to go down that should come down a little bit. But we are fighting for pennies and nickels here.

And you know Neal, we have got a lot of information in our deck regarding costs, and improvements quarter-over-quarter, and I think it is important to recognize that one of the reasons that we try to answer the questions with as much detail as we can is that why as Kaes pointed out, we have updated the market four times in the last month and a half. It is because when times are uncertain and our investors that own the company have questions, transparency is more important than ever. So, even though we might have had a free pass full of guidance, it is just not part of our culture of transparency. We are 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. So whether it is in background, or prepared remarks, or in the Q&A, that transparency is needed for tenants of Diamondback Energy, and we tend to follow that through these uncertain times and into the future.

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

You bet. Thanks Neal.

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 HBP drilling fell even further and you shifted rigs, focusing obviously on best well economics, which includes not only productivity but also obviously well costs and minerals position and infrastructure needs. So 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 the order of magnitude?

Well, there are two ways to look at well productivity. If you complete in the same well one month versus next is that productivity improved in the current month versus the prior month? And there is also a way that productivity looks better on a macro sense because you are shifting the mix of projects that you are doing. 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 our sub-division and then also not having to spend any or limited infrastructure dollars. So, we are still going to see that effect through the course of this year as our program migrates more into the Midland Basin side. And as I've answered now a couple of times, I still think there is room to see changes that we are making due to doing things better than we have done in the past, and those are the things that live on as the ones who make current.

Got it. I appreciate the color. That is it for me. I will turn it back. Thank you.

And 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 finances like they do. And so, really whether or not they continue to reduce costs is 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 are going through.

Appreciate the color.

Thanks. Good morning, I have one for Kaes, one for Travis. Kaes, 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 seaborn 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 is a physical slowdown bottleneck in any of these pipes?

Yes. I don't know all the details about the seaborn market, but as you know, it is more liquid than what we have seen especially in the last few weeks. So you are certainly starting to see spreads widening; barrels get on the water now, tanker rates certainly spiked a little bit, which would impact our realizations, but they have come back down a little bit here. Overall, the whole point of our marketing arrangement is to provide insurance in times of uncertainty, which we are in right now, and being able to call only four marketers and know that our barrels are going to move is something that allows us to sleep a little better at night. On the take-or-pay fees, 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 are about $20 million per pipe per year if we didn't send one barrel down the pipe.

Thanks, Kaes. 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 on regular completion crew?

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

I appreciate it. Thanks, Travis.

Good morning, Travis, you and your whole team.

Thank you, Charles.

Travis, you have anticipated? I guess my question in your response to your earlier one, I get the point that you guys are prepared 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 are better positioned than others in the industry to go back to work hard in the back half of the year. Is that inaccurate do you think and how would you elaborate on that?

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

Got it. And then may be following up a little bit on that, actually I guess if you are 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 is for lease retention or lease obligations consideration. I'm curious I imagine there have been other options you evaluated about going back to the mineral owners and maybe offering up a rental or some other thing. Are there other considerations that are going on that are leading up to completing 15 or 20 wells or so in 2Q rather than do some of those other lease obligation options?

Yes, Charles, you know a lot of those wells are probably already in progress, heading into the quarter so you can’t have that discussion in a mid-completion. We are working with our mineral owners and we happen to be pretty easy to work with through this given where we are in flat price. So if we can push out whatever we can whenever we can. We are trying to do that; it is hard to contact 40 mineral owners in a month in a 1,280 acre unit. 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 are actually inside, it is hard to communicate. But I will say, our land organizations and our land professionals, they are engaged—it feels like they are engaged every day and working tirelessly to negotiate lease terms to avoid having to drill or complete well when we are not getting paid for the commodity. So, as Kaes indicated, a lot of our mineral owners understand the business and are trying to make concessions. But also, it is 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, I am really proud of our land organization and the work they are doing to get us to the point where we are only running one completion to honor minimum obligations this quarter.

Thank you for the detail.

Thanks, Charles.

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 are drilling the areas with higher NRI and lower infrastructure needs?

Yes, Richard, I think we try to be as open as possible and show what our gross from that inventory is on Slide 13 and Slide 14 in the deck, and we update that every year. One of the benefits of slowing down is you are not burning through as much inventory that quickly. So I think without needing to complete 150, 160 wells to keep our production flat, 75% of it in the Midland basin, you got a pretty long runway of high-quality inventory to survive in a lower for longer environment.

We have got over 12,000 gross locations still in front of us, Richard and which is slowing down activity or stopping activity, exactly as Kaes said, we are actually extending our inventory runway as a result of completing those wells and adding to the license.

Okay. Thank you. And secondly, do you have 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, probably the way we are having discussions with the mineral owners right now on extending our delaying our next payer.

Okay. That is all from me. Thank you.

Thank you, Tullis.

Hey, good morning. Just had one, and obviously something we have talked a lot about in the past, but it is probably weird now. But as far as you have got plenty of inventory, certainly, but you are in a much better position than so many others around you. As you think about this playing out, and maybe some point getting more impressive. Are you seeing anything that is 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 environment?

Yes. Jason, this is all about demonstrating our financial strength and getting to the other side of the recovery. When we are there, and when the market signal is there, I think a question has more validity, but right now you know it is doing, what we are doing, which is maximizing cash flow and preserving liquidity.

Fair enough. I appreciate it. Thank you.

You bet.

Thanks, good morning. I appreciate the time, a lot has been addressed. But one that has 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 2021? Number one, what might those prices theoretically look like, it 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 frozen 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 have 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 had. If we were making changes at the end of last year, as an industry, with a slower growth and a greater return model; then I’ve got to take in the hyper-speed in March to this year. This new oil order as we look ahead, as we are going to have what feels like, at least today, it is going to feel like a lot lower growth in a more prescriptive way of returning investments or returning yields to our investors. I think it is still going to evolve in the course of this year, but certainly under what the strip looks like, it is going to definitely be a lot lower growth profile. But we want to make sure we maintain a dividend and resume when we maximize our cash flow, when appropriate market signals arise; you have purely growth there—all those tie together at the same time.

Okay. I mean is it fair to say in a $40 to $50 range all else equal today knowing that all else equal is a hard assumption to make but that that is just maybe round about the level that would signal getting back to a quarter-on-quarter growth profile?

Yes. It is more than just the just an oil price. I think I said earlier that if you look at some of the prices that we got in 2019, that certainly signal that you can get more aggressive on the growth, but I think we have got to be pretty careful in being super scripted on what exact price signals may look like before you get back to growth. Again, just want to make sure we maintain our dividends, maximize our cash flow and when it is time to grow; we will have to consider growth along with the dividend and maximize cash flow.

Understood, appreciate the color.

Just to finish that part, I kind of went on a little earlier about transparency, and I think it is important, again to emphasize here. We are trying to communicate as transparently as we can the way that we see the future, and you can count on us as the future gets clear. We are going to update the market. Like you said, we have done it four times in the last five weeks. We are going to continue to be communicative and we are going to continue to demonstrate one of the hallmarks of our corporate culture which is transparency, and we will let you know as these things evolve.

Sure, thank you. Listen, before I close this morning, I wanted to share with you guys a final thought. We have all had what feels like an unreasonable amount of time to reflect over the last couple of months as we have worked remotely or sheltered in place. When I'm not doing that, and looking back into over 35 years I've had in the industry, there have 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 are involved in a worldwide pandemic caused by the Coronavirus. But when I look back at those historical events 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 find a way to move forward. The second attribute, and I think it is important in today's environment is hope—hope that we will get through this and that our situation will get better. So as we get this country back to work, let's count on that resiliency once again. Let's also remind each other of 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.