Good day, ladies and gentlemen, and welcome to Diamondback Energy's Second Quarter 2020 Earnings Conference Call. All lines have been placed in mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. 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, Laura. Good morning, and welcome to Diamondback Energy's second quarter 2020 conference call. During our call today, we will reference an updated investor presentation which can be found on our 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. A reconciliation with the appropriate GAAP measures can be found on our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's second quarter earnings call. Before we get started, I'd like to take a minute to continue to extend our thoughts and prayers to all of those both directly and indirectly affected by the coronavirus pandemic. This year has brought unprecedented challenges, and I'm proud of how our organization responded given the obstacles presented. Our teams reacted quickly to the commodity price volatility and adjusted our operating and capital plans in real time. We are seeing the benefits of this work today with all-time low cash operating costs and capital costs per lateral foot at or below all-time lows in both basins. This is also accompanied by a high-graded forward development plan weighted towards the Midland Basin where we have high mineral ownership, low midstream and infrastructure capital requirements, and high returns due to the quality of our acreage, accompanied by industry low drilling and completion costs. Turning to the second quarter, we dramatically reduced our operated rig count in the second quarter, from 20 rigs on March 31st to six rigs today. In response to historically low commodity prices experienced in the quarter, we made the decision to complete as few wells as possible in the second quarter, with zero wells turned to production in the month of June. We also curtailed 5% of our oil production during the second quarter. This curtailed production has been restored and is now receiving significantly higher realized prices than it would have received when the decision was made to curtail. We have three completion crews working today to stem production declines and to meet our fourth quarter production target of between 170 and 175,000 barrels of oil per day. Importantly, Diamondback decreased activity levels throughout the second quarter while not spending excessive dollars on early termination fees or other one-time expenses that are headwinds to cash generation. Looking ahead, production is expected to continue to decline in the third quarter, but rise to meet our fourth quarter guidance as we began completion operations in June with two crews and added a third completion crew in July. We expect to run between three and four completion crews for the rest of the year and are currently running six operated drilling rigs, which is our base case for the rest of the year. In 2021, should a maintenance capital scenario become the base case, Diamondback can hold fourth quarter 2020 oil production flat while spending 25% to 35% less than 2020's capital budget, which is also expected to include lower midstream and infrastructure budgets. The second half of 2020 and 2021's capital programs will benefit from the drawdown of some of the DUC build from the first half of 2020 as we worked down our operated rig counts as contracts rolled off. We ended the second quarter with $1.9 billion of standalone liquidity and have only $191 million of our September 2021 notes outstanding after tendering for 55% of the original $400 million issuance during the second quarter. This was our only major term debt maturity before 2024. With our reduction in forward capital spending and expectation for true free cash flow generation at current commodity prices in the second half of 2020 and 2021, we will look to reduce both gross and net debt while continuing to return capital to our shareholders through our base dividend. This 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. To finish, Diamondback has further adjusted downward our already low cost structure and is prepared to operate successfully in a lower-for-longer oil price environment. A lot of the efficiency and cost gains made during this downturn will become permanent and will benefit Diamondback shareholders in a recovery. Low interest expense, low leverage, industry-leading low cash operating costs, downside hedge protection, strong midstream contracts, and the benefits of Viper and Rattler will allow Diamondback to operate effectively through an uncertain forward outlook. With these comments now complete, operator, please open the line for questions.

Your first question will come from Neal Dingmann. Your line is now live. Please go ahead.

First question. Travis, for your case, I guess we've heard a lot this year about how activity and pricing has impacted everybody's free cash flow. But, again, what we've noticed for you all, and you mentioned this in the press release several times, that your costs have come down notably again in 2Q. So, my question is how your cost control sets you up for free cash flow generation better as it appears to me your outspend is now behind you all.

Certainly, I agree the outspend is behind us. As I articulated the third quarter, fourth quarter, and throughout next year, we'll be generating significant free cash flow. The cost structure remains one of Diamondback's significant advantages. You've heard me say before that our main focus is to convert resource into cash flow at the most efficient margin while we drill and complete really good wells. The cost savings and the cost reductions that we're seeing right now through this downturn, we believe that a high percentage of those will continue throughout the forward development plan. Historically, when you go through a cycle, you'll see service cost concessions of 10% to 15%. We're now down over 25% over the last 12 months. As long as rig count stays below 200 rigs out here in the Permian and commodity prices stay somewhat range-bound where they are right now, we feel pretty confident that the execution and cost metrics that we're seeing today will be part of our future operating plan.

Leads me to the second one just on that plan, I was wondering, on the future activity cadence and leverage, specifically you guys have now mentioned a couple of times that you can keep '21 activity flattish with, I think you've said now, 25% less cost. So, the question would be, if prices stay about at today’s level into next year or maybe even go a little bit higher, would you still potentially keep activity levels flattish and cut debt or how would you think about it? Certainly, it sounds like you have the ability with these costs to come in a little bit better. So, I'm just wondering if prices do rally a little bit, as all others seem to be cutting productions out there. What's the thought of tackling debt or looking a little bit more at activity?

Certainly, we're not seeing any signals that growth is needed from Diamondback or from our industry in general. So, growth in today's world is pretty much off the table. The comments I made in my prepared remarks echo the board's viewpoint that our primary form of return to our shareholders is in the form of our dividend, and our board is committed to maintaining that dividend, and hopefully growing that into the future as well. Beyond that, excess free cash flow, as I said, we’ll be using to reduce debt. So, I think it's a combination of both continuing to lean into the dividend and also reduce total debt and net debt at the same time.

Yes, Neal, I think we're really focused on this Q4 exit rate number on oil of 170,000 to 175,000 barrels a day and maintaining that number in 2021 with the lowest capital required, whether that's on the midstream side, the infrastructure side, as well as the drilling, completing side. So, we're continuing to refine that and put some guideposts around 2021. But as Travis said, growth isn't top of mind today; instead, it's how capital-efficient can we be to keep that production flat in 2021.

Your next question will come from the line of Derrick Whitfield with Stifel. Your line is now live. Go ahead please.

I wanted to follow up on Neal's first question. Perhaps for yourself, Travis, or Danny. Could you speak to the repeatability of your recent operational records with the completion of the Spanish Trail four-wall pad in 10.5 days and the horizontal well you drilled in 8,000 feet in 24 hours? And if possible, help us kind of quantify the savings associated with that degree of efficiency versus your average well. And, Travis, we understand that every well can't be a pacesetter well, but we're just trying to get a feel for the degree of cost savings and how repeatable that could be for you guys in the future.

Yes, Derrick, Danny is in the room this morning and I’m going to let Danny answer those specifics.

Yes. First, on the kind of repeatability point on the completion side, I mean, really, that's a kind of operational procedural change from one of our service providers and a new kind of way of attacking zipper completion. So, that's repeatable on each pad we go to that we have those simultrack crews rigged up on. It's certainly something we anticipate going forward. And then as far as on the drilling side, the 8,000-foot in 24 hours, while that's a leading-edge kind of metric and it's a basin record and a Diamondback record, I don't expect us to be beating records on every well that we drill, but certainly, we'll keep edging closer to those types of results. And while that's the leading-edge marker, maybe the midpoint moves closer to that as we continue to utilize the technology that our partners are bringing us and start pushing the bounds of what we can do.

And then I think, Derrick, on the cost side, the completion crew that completes two wells at once and can - did that Spanish trail pad, you’re paying more for the horsepower, but you're also saving a lot of money on the variable costs. So, you're probably saving somewhere in the range of $20 or $25 a foot. And I think tangentially, that benefits areas where you have high water out or high production. You're watering out your production for a much shorter period of time and getting that production back online. So, that's a crew that we're going to use in areas where we have a lot of existing production throughout the basin.

As my second question, I'd like to shift to the evolving regulatory environment. Perhaps for you, Travis. You've correctly outlined your minimal exposures to federal land as a potential competitive advantage in the event there is non-supportive legislation with permits and/or fracking. With the understanding that you guys are one of the more progressive E&P companies on ESG matters and are not exposed to federal lands, could you speak to your greatest regulatory concerns in the current environment?

Yes, sure, Derrick. It's a lot of - we don't have a lot of clarity on what this - what the regulatory environment is going to look like if we fast forward to an administration change. But what we do know is that it won't speed up. Things won't become more efficient. And so, what we're trying to do is be as much on our front foot on things that require regulatory approval. Now, you've just echoed, and we have articulated, that we have essentially no exposure to federal acreage, but we're going to see what the new rules of engagement are, should they get rolled out. And you can expect Diamondback, like you said, to be progressive in the way that we navigate through those new rules of engagement. Listen, we support sound science that drives regulation. And you've heard me say that before in our sustainability report. And we'll continue to support regulation that's backed by sound science. When those two things deviate is where Diamondback and our industry are likely going to have a problem with the regulation.

Your next question will come from the line of Scott Hanold from RBC Capital Markets. Sir, your line is now live. Go ahead please.

Thanks. You all in your presentation, on pages I guess 10 and 11, provide your current inventory. And you do have that economic sensitivity. And it looks like the Midland Basin is pretty resilient in this assessment, down to at least $40 to $45 a barrel. Could you give us some sense of what causes that resiliency? Is it the current well costs and maybe if you can give a little bit of color around that inventory, where you think that relative, I guess I'll call quality is, versus what you've drilled to date and maybe versus what you see with - compared to other peers?

Yes, Scott. I think it's misunderstood how good our Midland Basin inventory is. I'd kind of put our Midland Basin inventory particularly with our cost structure, up against anybody. And that's just proven based on the numbers. So, with current well costs below $600 a foot on the Midland Basin side, we have a significant runway of quality inventory ahead of us. I think we wanted to get ahead of that discussion topic, which seems to poke its head out once in a while. So really, on the Midland Basin side, putting zero dollars of value on the gas side at $35 a barrel, you have over 3,000 locations economic today. And I think that that speaks to the quality of inventory and the cost structure behind that inventory.

Yes. And I guess my specific question would be - and you talked about well costs and you obviously have a royalty rate advantage, but can you talk maybe about the like EUR and productivity, say relative to some of your peers? Or is it really the cost and the royalty advantage?

It's really a combination. Some of our peers, mostly the peers that are larger than us that have a significant amount of inventory, they're spacing their wells wider and doing bigger frac jobs, so they're getting a little more EUR per foot, but the costs are higher. We've tended to space our wells relatively tighter at eight wells across 660-foot spacing in the Midland Basin, and that's partially due to the completion design being a little bit smaller frac job, but also the costs being lower, and therefore getting a little lower EUR per foot, but from a returns perspective, you’re drilling and completing those wells for multiple hundreds of dollars per foot cheaper.

And then my follow-up question is on the conversation of maintenance spending into next year. How many wells does it take to maintain your production? And to maintain that 170 to 175 on the oil side, would your oil cuts stay flat? I mean, what does your oil cut do through like 2021 on a maintenance plan?

Yes. I think oil cut comes up a little bit from where it was in the second quarter because of the curtailments, but we're probably still somewhere in the low-60s now. Our maintenance plan in 2021 is moving more and more towards the Midland Basin. So, that probably means a few more wells than if you were 50/50 Midland Delaware. But I think something similar to our gross operated well count this year with two-thirds or more focused on the Midland Basin is kind of where our head is at. And I think, as we're doing our work right now to refine that analysis and refine that 25% to 35% less capital number, we'll update the market when we have that data.

Your next question will come from the line of Gail Nicholson from Stephens. Your line is now live. Go ahead please.

You guys have had a nice improvement in LOE. Can you just talk about how you think LOE trends physically in the back half of 2020, and then more importantly in 2021 and what drivers you have done to gain that further improvement?

Yes, Gail, really, credit to the team and the field organization who went from ramping up in April to curtailing in May and bringing back that curtailed production in June to keep LOE as low as it did in the second quarter, below $4. I think that, naturally, that number is going to come up a little bit in Q3 and Q4. But still probably be somewhere in the lower half of the four. Then, as we think about the next year, our large capital spend on the infrastructure side in terms of electrification of some fields as well as going to gas foot projects will help LOE stay in that kind of low 4's range as we head into 2021. And every cent at current production is about $1 million a year of cash flow. So, we're picking up pennies and going to stay focused on being as close to that $4 bogie as we can.

And then, in ‘21, your take-or-pay obligations or firm sales increased with the start-up of Wink to Webster. I was just kind of curious how you guys are thinking about price realization expectations in '21 per percent of WTI and the importance of having that exposure to Brent as we move forward in time?

I think the exposure to Brent stays about the same 2020 to 2021, about 60%. But once Wink to Webster comes on, that contract moves from a Midland-based price to MEH-based price. I think our mentality there, the thought process is these types of commitments and the long-term sales agreements are essentially large insurance policies for when things go bad. And right now, with Brent WTI as narrow as it is, we're probably losing a few cents versus selling those barrels in Midland. But if Brent WTI blows out to $4 or $5 a barrel, then we're probably receiving somewhere close to 100% of WTI.

Your next question will come from the line of Asit Sen from Bank of America. Your line is now live. Go ahead, please.

The DUC count of 110 to 140 at year end ‘20 and you talked about drawing those, what's a good way to think about a normal DUC level in this scenario? And if you could - I know it's a little early, if I'm thinking about maintenance capital in 2022 at current strip, how should we conceptually think about Midland, Delaware split and capital needs for infrastructure?

I'll take the second part first, Asit. I think, overall, infrastructure is - the line that we define as infrastructure will be cut almost in half going into 2021 and I think that number, we've had a large infrastructure build across our position over the last three or four years and there's a lot of scrutiny on that number to not come back up. As we have executed on our one-time projects on electrification and gas lift, and we have very few new batteries to build, instead we expand our existing batteries, that infrastructure budget is going to keep being driven down. Even in 2022, that's a long way from today. But I think our goal is to try to be at least two-thirds Midland Basin-weighted for the foreseeable future. And whether that's in a growth or a stay-flat scenario, I think we have the inventory to do that.

And then my follow-up question is on the ESG front. Travis, you emphasized the ESG, and on slide 20 flaring as a percent of net production has come down pretty nicely year-over-year. Could you talk about strategies enabling this? Again, remind us on the compensation metrics as it relates to ESG?

Yes, specifically, our field organization and operations organization jumped ahead and took advantage of some of the slowdown in our drilling activity to kind of get caught up on some of the Diamondback-required drilling and completion operations, particularly in the Delaware Basin. In some instances, we brought our balance sheet to bear, where we spent dollars to eliminate flaring, but it's essentially across the board a high emphasis to not flare at all. And we do need, at times, help from our gathering partners to make sure that once we're hooked up that that can move the gas. But in general, we've adopted a policy of every well is connected to a gas sales point before it's brought on. And that, plus working closely with our gathering and processing partners, has allowed us to really substantially reduce our flaring.

Yes, and, also, we haven't taken the matter into our own hands by converting some of these legacy contracts that we had from percent of proceeds into 100% fixed fee. And that's what's driving our gathering and transportation costs to go up by a little bit this quarter. Now, we catch the benefit of that on the realized price side on the gas front, so it's really a neutral trade. And the higher gas goes up, the more we're exposed to that on the Diamondback side. So, using the legal and the contract route to incentivize our gatherers and processors on a fixed fee basis to take our gas.

And we've got - in fact, you can read it on Slide 21, some of the changes we made to our short-term incentive compensation program. And as a reminder, this scorecard, this corporate scorecard that we present in our proxy, that makes up half of every employee's short-term incentive compensation on an annual basis. So, we've got a 15% weighting on our ESG measures. And you can see what those are on Slide 21. Listed there, safety metrics, our flaring, greenhouse gas emissions, the percent of recycled water, oil spill control and TRIR or total recordable incident rate. There's five measures that make up that ESG score now.

Your next question will come from the line of Jeff Grampp of Northland Securities. Your line is now live. Go ahead, please.

You guys have communicated pretty clearly an aspiration to reduce debt here on an absolute relative basis over the next few quarters. So, I was wondering if you guys had targeted either an absolute or relative level on the debt side that you guys would want to get to before assessing and increasing returns to shareholders.

Jeff, I don't think they're mutually exclusive. We've raised our dividend every year since putting it in place three years ago and I think that being the primary return of capital, we're going to look at that very closely at the end of the year and see what 2021 holds on that front. The one consistent theme we received from our largest shareholders over the past few months is to protect the dividend, and in exchange for protecting that dividend, cut capital. And that's what I think we're going to do. I think overall, we would like our debt to be lower than higher. And I don't want to put out a two-year or five-year target on that front because a lot can change in this business, as you've seen in the last three months. But I do want to also emphasize that at the parent company, we still have three companies, right? And each of those companies has debt that's manageable. All three companies will be generating free cash flow starting in the third quarter going forward. And on top of that, Diamondback has a lot of ownership in those two subsidiaries, which while you can't sell all that in a day, at some point that is a safety valve for how much debt you think you have at the parent company.

My follow-up, Travis, wanted to pick your brain on the M&A front, maybe from a couple angles. First, just generally, your comfort level at taking a serious look at any deals in this environment? And second is just any level of interest in terms of diversifying the asset base outside of the Permian? Do you see benefits to that from Diamondback's perspective? Or do you think it's more of a competitive advantage to have the concentration and the knowledge space that you have in the Permian?

Look, in terms of the first part of your question, M&A, we are so internally focused right now on doing the things that we need to do. Look, our industry's been rightly criticized for all kinds of noise that have distracted from returns, and our focus right now is singularly trying to deliver the highest returns and cash flow for every single dollar we invest. And look, from the public guys, the debt's trading so poorly for the public guys that could potentially be targets, it just doesn't make any sense for us right now. So, that's kind of my view on M&A. And then, I just don't think that it makes sense for Diamondback to be looking at other basins. One of the core philosophies we talk about here is know what you're good at. And Diamondback is really, really good at Permian Basin extraction of hydrocarbons. And that's borne out by our cost structure and our execution metrics. And that's our emphasis. That's what we're good at; that's what we know we're good at, and that's what we're going to maintain.

Your next question will come from the line of an analyst from JPMorgan. Your line is now live; go ahead, please.

Travis, your guidance implies a - call it a 60/40 split in footage between the Midland Delaware Basins this year. I was wondering if you could give us maybe some more thoughts on how that mix could look as we head into the back half of the year and perhaps any preliminary thoughts on 2021.

Sure. I'm going to let Kaes answer that. He's got a spreadsheet in front of him.

Yes. The 60/40 really is driven by a lot of the first half of the year being in the Delaware Basin. And looking to the back half of the year, Q3, Q4, and into 2021, we’ve really moved the rig schedule on the frac schedule to about 70/30 Midland Delaware. While I don't have my spreadsheet in front of me, that's kind of the path forward is let's get more focused on the Midland Basin where we have less infrastructure needs, less midstream needs, lower LOE, and probably better returns in our overall cost structure. So, I think for us, six rigs operating, four of them are in the Midland and two in the Delaware.

And, Kaes, if you were going to characterize what the spread and call it an oil breakeven is today, kind of using some of your leading-edge well cost, what would you say the spread is?

I'd say it's less than $5, but somewhere around $5 a barrel. Your breakeven in the Midland is a little bit lower than the Delaware. I just think if you're running $5.75 or $5.80 as your cost per lateral foot, that's a pretty good return in project with some of these Midland Basin wells in the 80, 90, 100 barrels a foot EUR range.

And just my follow-up, quite a few of incoming questions just on next year's CapEx thoughts. Obviously, you released this a couple - two, three weeks ago, but just the 25% to 35% of decline per year to keep 4Q oil flat, you did highlight some lower infrastructure costs, but what type of well cost is kind of embedded within that range? Are you using basically the 2020 updated outlook for well costs? But maybe just a little bit of color on that would be helpful.

Yes, I don't think we would use the 2020 updated outlook; the real-time cost to drive that number. We're really kind of using the lower end of our full-year 2020 guidance range. We - I think Travis mentioned earlier in the call, well costs are down 25% year-over-year, probably 50% of that is service-cost related. I think for us to guide to all-time low well costs in 2021 would not be a prudent idea.

Your next question will come from the line of Jeanine Wai from Barclays. Your line is now live. Go ahead, please.

My first question is following up on some of the prior ones on productivity and activity allocation. Can you tell us how you anticipate the corporate-wide productivity per foot to trend in 2021 relative to 2020? And I guess we're asking because I know that there's been some change recently and there's some preference between high-grading zones in a more modest price environment versus more co-development versus kind of needs retention.

Well, I think, Jeanine, overall, with more Midland Basin as a higher percentage of your total capital, your Midland Basin EUR per foot is lower than the Delaware, but your well costs are significantly lower. So, while I can't give you an exact productivity on well EUR per foot, I do think, in general, the couple hundred wells we’re going to complete in 2021 will be a higher productivity on returns basis than 2020 because in 2020 we were heading into the year to complete 350 wells and we've slowed that machine down to complete 185 this year and something close to that next year. And I think just, in general, our next if 80, 85 wells I see on the schedule for the second half of 2020 are significantly better than the first half of 2020, and we expect that level of detail on drilling our best stuff first to carry into 2021.

My second question is just back on CapEx. I know you pre-released the updated production and CapEx guide. Last night, you provided the helpful breakout between the different components, which were kind of reset to the higher end. Not to rehash old news or anything like that, but I still think that there's a lot of questions on some of the moving pieces on that 2020 update. Especially on the drilling and completion side, given you're completing the same amount of net wells you previously planned and exiting with some less DUCs. Maybe color there for some clarification would be helpful. Thank you.

Sure, Jeanine. I think what's unique about how Diamondback reports CapEx is that it's a number that actually matches the cash flow statement. And sometimes, that's been to our detriment, particularly in the first half of the year. So, in general, we came into the year running 23 rigs and eight completion crews, and we're going to exit the year running five or six rigs and three or four completion crews. And that results in a net cash outflow and a cash drag of $250 or $300 million on the budget. I think for others who report a crude CapEx that doesn't match their cash flow statement, we, on an activity-based basis, are going to do 155 to 160 of capital this year with a large cash outflow drag heading into next year.

Your next question will come from the line of Leo Mariani from KeyBank. Your line is now live. Go ahead, please.

Want to follow-up a little bit on the cost side. Certainly, looking at your leading edge well costs that you guys are talking about in your slide deck in both the Midland and Delaware, certainly those appear to be below your 2020 guidance in terms of costs per foot. Just trying to get a sense there, do you think kind of the full year ‘20 Midland and Delaware DC&E well cost per foot guide might end up being a little bit conservative, or are you kind of maybe being a little reluctant to change things sort of mid-year here?

I think we're reluctant to change it just because half the year's gone, and the way we report CapEx, probably three-quarters of the year is essentially gone on well-cost perspective. But these lower well costs that we're seeing today in real time will benefit the company in the fourth quarter and into 2021. So, I think it's prudent for us not to change that guidance. But certainly, we expect the trend to continue.

And I guess, clearly, you guys are very focused, it seems to be, on maintenance mode in a $40 oil world and rightfully so. Travis, you certainly talked about not having the right signals in this current environment to really indicate for anyone in the industry to pursue production growth. I guess, what do you think the right signals might be for the FANG and U.S. industry in general to start thinking about production growth?

You've got to have a lot higher commodity price. I don't know what higher means, but certainly materially higher than what you see today. You also have to have access to capital, which right now's been - there's been capital starvation for a number of quarters for our industry. And rightfully so, as I mentioned earlier, because of our industry's inability to generate through returns, but the last part of that would be - certainly, investor sentiment would have to change dramatically from where it sits today. There's quite a bit of headwinds, I think, for our industry as you look ahead to try to think about any kind of meaningful production growth.

Your next question will come from the line of Charles Meade with Johnson Rice. Your line is now live. Go ahead, please.

Good morning, Travis, Kaes, and the whole team there. I wanted to ask, Travis, this goes back to a comment you made earlier in response to one of your earlier questions about the rig count staying under 200 in service costs. If we go back to the end of last week, a couple of the bigger operators out there, two majors, I think everyone expected them to be dropping rigs, but they really indicated that they're going to be dropping quickly or dropping a lot of rigs into your end. And I'm curious, as you look toward the back half of ‘20 and into ‘21, as that rig count continues to go down, how do you see things changing for you as an operator? Or maybe just in your environment in the greater ecosystem out there?

Well, certainly if we continue to have this environment, as I mentioned earlier, well costs are usually going to stay the same or they're going to go lower. And I think it's reasonable, if commodity prices increase, you'll start to see the service sector - the service sector responds. But look, the Permian Basin is going through a seismic shift in capital allocation from all the operators, and you can see it in the production responses. We're now below 4 million barrels of oil a day of production. And so, it's just hard to see, in this environment, any meaningful change in the current operating situation that all the companies are faced with here in the Permian.

Got it, that's it from me. Thank you.

Yes, and Charles, just to add to that though, with this continued reduction in activity, and even in this environment, I can't emphasize enough that Diamondback's clear advantage is not only the number of locations we have that we laid out in our slides in terms of inventory, but it's our cost structure. And so, and - the lower the price of the commodity goes and the more the margins get squeezed, the more really efficient, high-margin companies get highlighted. And certainly Diamondback, as evidenced by numbers in this release, falls into that category.

And your next question will come from the line of Brian Singer from Goldman Sachs. Your line is now live sir. Go ahead, please.

Can you talk to how this year and the run-up to this year have changed your views, if at all, longer term on the oil price on the right amount of production to hedge? And then, if we are in a lower Diamondback plus industry growth environment in the Permian, the strategic value of your interests in Viper and Rattler?

Brian, the - Kaes mentioned earlier about how Diamondback has a large ownership position in both our subs, and that continues to literally and figuratively pay dividends to Diamondback shareholders. And it's something the Diamondback board is aware of, but it's - we're comfortable in our position in our ownership of those subs today. You want to add anything to that, Kaes?

No, I think on the hedging side, most of our hedges we structured as two-way callers. And so, we had a slide in our deck where we are exposed to the upside here and we have a good amount of 2021 production hedged. We haven't added much on that front. We've actually restructured and lowered the total exposure in 2021. But overall, I think we’re moving towards a true free cash flow model that distributes a lot of cash to shareholders. Diamondback should emulate what Viper and Rattler have done over the past couple of years, which is distribute a lot of cash back to their shareholders, one being Diamondback. But more hedging, I think, is probably in our future and making sure your dividend is protected on the bottom end and you print a bunch of free cash on the top end of those two-way callers.

And then my follow-up is, what are you seeing from outside operators in the Permian? And if oil prices do rise, do you have a sense if the level of discipline from the onsite operators will be lower or greater than your own? Well, certainly our industry doesn't have a good track record of that discipline. But I believe that there has been a change in sea level in terms of discipline. And I'm confident that all operators, that at least have any awareness of our industry, are going to be very judicious in trying to resume activities that generate production growth.

Your next question will come from the line of Michael Hall from Heikkinen Energy. Your line is now live. Go ahead, please.

Appreciate the time. I just wanted to do, I guess follow-up on one thing and then also ask I guess, on base declines maybe first on the declines. I'm just curious, as you guys have slowed down a bit here this year. How do you think about the impact of that on the base decline profile as you look at 2021 exiting 2020, entering 2021, relative to how things look exiting 2019 heading into 2020? What's the change in base decline rate there?

Yes, Michael, on the oil side, we released - high 30s was our base decline exiting 2019 going into 2020. I think that probably goes somewhere into the mid-30s. I can't guarantee the low-30s yet, but probably the mid-30s on at least on oil. So, probably 300 bps or 400 bps of benefit, on the BOE side, we were at low 30s, kind of 32, 33 this year, 2019 going into 2020 and that probably goes down a couple of hundred bps lower into the near 30% range.

And I guess the follow-up was on the M&A commentary. It seemed like maybe Travis, you were referring to the public space in that commentary. I just wanted to follow-up, is your view that M&A doesn't really make sense? Is that applicable in both public and the private space or is it worth differentiating between the two at this point?

Well, it's all about the rock, right. So I mean, if you find good rock, you shouldn't care whether it's public or private. But the problem that we're seeing on the public side is how poorly the debt's trading for public companies. And that adds a significant detriment on acreage valuation. On the private side, there's just not that many opportunities out there truthfully of Tier 1 acreage. We're not going to - there's just not a lot of Tier 1 rock that's out there and that's kind of how we differentiate it.

Your next question will come from the line of Richard Tullis from Capital One Securities. Your line is now live, sir. Go ahead, please.

Kaes, it was mentioned a couple of times that the dividend is the primary vehicle for returning cash to shareholders. Just wanted to get your thoughts on potentially Diamondback implementing say, a variable dividend that paid out a certain percentage of excess cash flow yearly?

Yes, I mean, Richard my opinion is, I've heard a lot of talk about the variable dividend. And the only variable dividend I've ever seen is at Viper in our space. But for us, the fixed dividend is the priority. And I think in the conversations with our larger shareholders, they want to be running, kind of, a dividend growth model as how they're getting cash back from their investment in Diamondback. And I think overall, it's a good concept, but it's just not a concept that we're focused on right now. We're focused on the base dividend, which in our peer group has the highest yield today. And I think investors knowing that's safe is important and knowing that that's going to grow in the future is also important.

Sure. And then just as a follow-up, looking at the base case 2021 budget of around six rigs, maybe for Travis or Danny, do you envision allocation of some level of capital in that scenario to continue testing your acreage, such as going back to the limelight area or other intervals?

There might be a little bit in there, Richard but it's going to be as muted as possible. I think given the shocks that the industry's gone through over the last four months just exemplifies how precious capital is. And I think a lot of our landowners have been pretty accommodating through this. And we're going to do what we can to hold acreage, but also to only drill our best stuff with the majority of the capital.

Yes, Richard, we remain singularly focused on delivering the highest returns and cash flow per share for each dollar that's invested. And every capital allocation decision that we make runs through that aperture and we'll be consistent with that on a go forward basis.

Thank you, sir. I am showing no further questions at this time. I would now like to turn the conference back to CEO, Mr. Travis Stice.

Thank you again to everyone for participating in today's call. If you've got any questions, please contact us using the contact information provided. Stay well.

Thank you, sir. Thank you so much, presenters. And again, thank you, everyone, for participating. This concludes today's conference. You may now disconnect. Stay safe and have a lovely day.