Ladies and gentlemen, thank you for standing by, and welcome to the Diamondback Energy Third Quarter 2020 Earnings Conference Call. I would now like to hand the conference to your speaker today, Adam Lawlis, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Victor. Good morning, and welcome to Diamondback Energy's Third 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'll now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's third quarter earnings call. Diamondback continued with our trend of cost reductions in the third quarter, with lease operating expenses and general and administrative expenses remaining near all-time lows and capital cost per lateral foot continuing to decline to new records. Our drilling and completion operations continued to gain efficiencies, and current well costs are now 30% lower than 2019 levels in both the Midland and Delaware Basins. We're also beginning to see the benefits from high grading our development programs since the downturn started in our latest well results and have all of the impact of curtailments from the second quarter in the rearview mirror. As a result of this high grading and improved capital efficiency, we're on track to meet our fourth quarter average oil production target of between 170,000 and 175,000 barrels per day and expect to carry this momentum into 2021 as the baseline for our maintenance capital development plan in 2021. We expect to execute on this capital plan with 25% to 35% less capital than 2020. This plan implies a reinvestment ratio of about 70% at $40 oil. To be clear, this maintenance capital scenario is currently the base case for our operations through the end of 2021. But if commodity prices weaken further and sustain that weakness for an extended period, we will exhibit capital discipline and industry leadership by cutting capital and activity levels further. The conversation in the industry has moved towards touting reinvestment ratios and corporate breakevens, but has shifted away from answering the question of whether or not an operator's development plan is generating sufficient returns and creating net present value for that company's shareholders. While our 2021 corporate maintenance capital breakeven of low $30s WTI before paying our dividend should be considered best-in-class, that scenario will not happen if we're operating at or near breakeven. We will be spending less than maintenance capital to preserve upside for our shareholders and will instead need to conserve cash flow to pay our dividend and to pay down debt. Put very simply, our forward capital allocation philosophy has not changed. We will protect our dividend, spend maintenance capital at most, and use excess free cash flow to pay down debt. If our expected free cash flow will not cover our dividend, then we will cut capital to ensure our dividend is protected. The third quarter of 2020 provided a preview of this new operating model as we generated $153 million of consolidated free cash flow in the quarter, most of which was used to reduce consolidated net debt by $137 million. Looking ahead, we have only one material term debt maturity due in the next four years, $191 million that remains outstanding on our 2021 maturity. We expect to have cash on hand to retire this note by early 2021 to further reduce absolute debt. After this maturity, we do not have any material outstanding obligations until the end of 2024. We also have a legacy high-yield bond due in 2025 that's currently callable, providing optionality for future gross debt reduction. Turning briefly to ESG. Diamondback is committed to environmental stewardship and delivering best-in-class performance in reducing our carbon footprint. While owning and operating assets that are positioned on the low end of the global oil cost of supply curve is most important to our stockholders, we recognize it's also important to own and operate assets that are also positioned on the low end of the greenhouse gas emissions cost of supply curve. Diamondback supports public policies that eliminate routine flaring as long as those policies protect the safety of our operations and consider flaring contributions from all segments of the oil and gas industry. Upstream and midstream operators must continue to work together to address the flaring issue for our industry. Diamondback has been proactive in reducing our flaring by using our balance sheet to build infrastructure to ensure every development well completed is ready to be connected to each respective midstream gatherer. We will not flow back a well if that's not the case. We've also restructured gathering and processing contracts at our expense by converting contracts from a personal proceeds contract to a fixed fee contract so the gatherer does not have an economic excuse not to take our gas. This puts all of the commodity exposure on us as the operator, but ensures that our gas is not flared. Flaring was responsible for over 50% of Diamondback's Scope 1 emissions in 2019. With flaring per net BOE produced down 54% year-to-date, our Scope 1 emissions have materially declined this year, demonstrating our commitment to environmental responsibility. Next, on the topic of industry consolidation and M&A, we believe that consolidation in our sector is necessary as our sector is too fragmented, but that's changed rapidly. Industry consolidation has long been anticipated in U.S. shale and has been touted as an avenue to create scale and improve cost efficiencies. Today, Diamondback is a leader in cost and efficiency. The success of the acquisitions we've executed to date were largely driven by realizing hundreds of millions of dollars of savings through lower costs and higher returns than from the previous operators. A well drilled in the Permian Basin by Diamondback today will be quicker, less expensive, and operated with the lowest cost structure in the business. So we do not need to increase our scale to further reduce our cost structure. We produced 300,000 barrels per day at the lowest cash and capital costs in the industry. We also have an investment-grade balance sheet with proven access to capital, even through this pandemic. There's not a piece of the supply chain that would be better for Diamondback if we were larger than we are today, from midstream contracts to service availability to access to capital. These facts should prove to investors that we have the scale necessary to compete in this industry. Touting arbitrary numbers such as a level of production our market cap deemed to be relevant in our space is both specious and self-serving. This commentary is only coming from companies with those arbitrary characteristics and is not based in fact or proven through operational metrics. Diamondback is not getting left behind if we don't do anything today, and we prefer not to make rash decisions at the bottom of the cycle. Patience will be rewarded at the end of the day, and we have the balance sheet, cost structure, and asset base to be patient and ride out this downturn as brutal as it may be. Getting bigger does not always translate to getting better. Better is what should matter to shareholders, and better does not mean that financial metrics are improved in that first year. Better means the acquirer adds inventory that competes for capital right away at a relative value that's accretive to the acquirer's shareholders, not the targets. Whether the transaction is a merger of equals or selling the company or buying something, the transaction must translate to being better for our shareholders who own the company. If that is the case, then that's what we'll do. To finish, we operate in a cyclical business. While this downturn has been as severe as any in industry history, Diamondback has the size, scale, balance sheet, asset quality, and cost structure to weather a prolonged downturn and thrive in the inevitable upcycle. We are generating and expect to continue to generate free cash flow, and we will allocate that free cash flow to our dividend and debt reduction until commodity prices meaningfully recover from current levels. With these comments now complete, operator, please open the line for questions.

Our first question will come from the line of Arun Jayaram from JPMorgan Chase.

Travis, it's clear from your commentary that you believe you have sufficient scale to effectively compete in the Permian without M&A. That being said, I was wondering if you could give us your views on the A&D market? Because it does appear to be what several of your peers have characterized as a buyer's market. We saw a natural gas deal, obviously, not in the Permian, which was recently transacted at a PV17 valuation. So maybe just start with your thoughts on what you're seeing in the A&D market?

Let me return to your emphasis on scale. No service company has approached us indicating that our size is a concern for conducting business. We have presented a strong case regarding Diamondback's size, scale, balance sheet, and execution metrics. However, predicting M&A activity is challenging for me. It's essential to focus on my previous statements: we will grow our asset base as we have consistently done, only when we can demonstrate that it will enhance shareholder value. This has been our approach since October 2012 when we went public. Every day, we concentrate on how to drive shareholder value, whether through operational execution or M&A.

And just my follow-up is one of the drivers of the reduction in your cash cost guidance was lower LOE. And I think that some of that, Travis, has been a shift towards gas lift from ESPs. I was just wondering maybe if you could articulate how your artificial lift strategy has evolved and any implications for go-forward LOE and decline rates?

Sure. I'm really proud of our operations organization. Particularly, this skill set on gas lift really came through the legacy Energen folks, and it's a tribute to those guys. They showed us how we could accomplish our lift mechanism using gas lift instead of what Diamondback's legacy operation practice was with electric submersible pumps. Now we still have a lot of electric submersible pumps in the ground. But we've been making a fundamental shift in going from electric submersible pumps to gas lift, and we're seeing a significant reduction in cost savings. And at the same time, we're not seeing any detrimental impact on performance, so it's something we're really excited about. If you just step back from it, these electric submersible pumps, while it's pretty easy just to crank the wrist up or down in response to volume needs, at the end of the day, you're hanging an electric motor in water, one and a half miles underground with an extension cord, and there are nothing but bad things that can happen in that scenario. So there's still going to be a part of our operating plan, but we're really excited about some of the leading-edge technologies we're deploying with gas lift. On the expense side, our focus has always been to be the lowest cost operator in the Permian Basin. Our organization understands that for every one cent that we save in costs, whether it's lease operating expenses or general and administrative expenses, that translates to $1 million of cash flow that we can return to shareholders or whatever. So when you have a mindset that's focused on pennies, from the boardroom out to our field organization, that's how you ultimately end up driving best-in-class cost structures, which is what Diamondback consistently delivers on.

Our next question will come from the line of David Deckelbaum from Cowen.

Can you elaborate on how the high grading benefits you are experiencing with the 2020 plan might impact the 2021 plan? You mentioned that you are projecting free cash flow of $525 million at $40. Will high grading provide additional benefits in 2021? Also, considering Diamondback's scale, how long do you believe you can maintain this high graded program at a consistent level?

Yes, David, I think we made some very tough decisions at the end of Q1 and into Q2 as we ramped down from 23 rigs to five today. While we did that, we did move the drill schedule to a higher Midland Basin percentage of total capital. We've kind of put the worst of our lease obligations behind us in the Delaware Basin and now can focus on drilling and completing our best stuff first. While you're in a world where we're completing 350 wells a year and running 23 rigs, that might be a little more difficult than today when we're running six rigs and completing less than 200 wells a year. So finally seeing the well results and the productivity improvements from moving to a higher Midland Basin percentage of capital combined with high Viper interest, as you saw in the Viper results for this quarter, and lower midstream and infrastructure spend has resulted in a little more capital efficiency. I think a nice setup from a well result rate of change story heading into next year. How long can we sustain that? I think we've been as transparent as anybody in this industry on what our location count looks like. We've had it in our decks for the last three years, and with well costs coming down to where they are today, our Midland Basin productivity can stay at or above 2021 levels for a multiple-year period. I don't know what the exact number of years is; it depends on what happens with oil price and activity, but we're confident we can stay flat with less capital going forward as decline rates come down and productivity goes up.

David, I can tell you from my chair and looking at this kind of two-thirds Midland Basin, one-third Delaware or three-quarters, 25%, that capital allocation looking out for the next, I don't know, four to six quarters, I'm as confident in our forward plan as I've ever been. I mean we're really firing on all cylinders on execution, on cost reductions, and very confident in this forward plan to be able to deliver what our shareholders expect.

I appreciate that. And just my follow-up is on the '21 plan. I think you mentioned midstream and infrastructure spending coming down next year. Can you clarify those comments a little bit more and maybe talk about some of the benefits or value creation you see evolving out of Viper and Rattler back to FANG holders?

Yes, David. So you know what, I think we've kind of said that midstream and infrastructure will be down another 50% or so next year from this year's levels. If you look back to two years ago, that's about 25% or 30% of the levels we had in 2019. So all of that is coming down. It allows us to spend more capital on the drill bit versus the easy ancillary stuff that does have a benefit and does reduce our cost structure. But with the slowdown, we're not having to add a lot of disposal capacity or oil gathering capacity or a lot of new batteries because we're utilizing our existing infrastructure efficiently. We're looking forward to that continuing to decrease. On the Viper and Rattler side, those two businesses are still very strategic to us. They provide a lot of free cash flow up to the parent in the form of distributions. Both of them are fine from a leverage perspective. Therefore, you're going to get more cash up to the parent in 2021 from those two companies than even 2020.

David, I just want to circle back on your question of inventory. Kaes articulated that we're only going to burn maybe 150 wells per year on the Midland Basin side of things. That translates to years of future inventory. When I talked about confidence in the next several quarters, that doesn't mean that I'm not confident in the next several years. We've got 350,000 acres here in the Permian. The slower we go, the more we and the industry go towards maintenance capital, it just extends whatever the perception of inventory life is. It extends it out because we're just not playing through it at the same pace we were last year when we were running 20-plus rigs. I hope that clarifies that a little bit.

Our next question will come from the line of Gail Nicholson from Stephens.

You guys are entering a phase of very attractive free cash generation on a myriad of oil prices. When you look at debt paydown, what is the appropriate amount of immediate debt paydown versus making sure you have cash on the balance sheet if the commodity price continues to be volatile?

Yes, Gail. I think, first and foremost, we need to have $191 million on our balance sheet to pay off our September 2021 note. As Travis mentioned in his opening remarks, we plan to have that cash by early Q1 of next year. On top of that, we do have the fortune of having a former high-yield bond in our 2025 bond that's callable. Unlike the IG bonds that we have outstanding that are bullet maturities, we have some flexibility in paying down that bond by calling it. I don't know when that's going to happen, but that's the logical next step. Overall, while we're not big hoarders of cash, we should keep more of a cash balance than we have in the past given the volatility as well as the issues that come up with bullet maturities. You must have cash on the balance sheet to handle those. Our plan is to make sure we have a little more cushion and rely less on bank financing overall.

And then looking at your free cash flow scenario on Page 7 of the presentation, you guys are using a 95% WTI realization there. I believe by the fourth quarter, 60% of your volumes should be getting Brent pricing. So I was just curious what Brent-WTI differential you're using for that 95% WTI realization?

Yes. So we're using $3 there. That ratio is a little tighter right now. Because we're more exposed to Brent, the narrower Brent-WTI or Brent Midland spread has hurt us a little bit. I'm ignoring the fact that we do pay ourselves via our ownership in the pipeline to get to the Gulf Coast. But should that Brent-WTI spread widen, we'll naturally benefit. On our Brent realized pricing, we're realizing a Brent less $5 or $6. For the rest, you're realizing an MEH price or a Midland direct price for now.

And our next question comes from the line of Neil Deman from Tourist Securities.

Travis and Kaes, you mentioned productivity and your confidence. Can you clarify what you believe is the main driver of this productivity? Is it primarily due to asset location, operational efficiencies, or a combination of both? What gives you the confidence you seem to have for the upcoming quarters?

Yes, I think it's all of the above, Neal. I mean, I don't think anyone's ever questioned Diamondback's cost structure or our ability to execute on the capital side. Overall, I do think the Street does look at these curves intently. We're particularly focused on putting out some better curves over the next few quarters, if not years. We've seen that drive positive rate of change stories on the Street, and we hope the Street picks that up as well.

Okay. To follow up, Travis, regarding scale, do you believe the ongoing discussions emphasize the need for more scale? I've heard people mention it in terms of producing more optimal pads and having better areas in plays. Could you share your thoughts on that? It seems like this topic comes up frequently. I’d like to understand your perspective on how you view your position compared to peers, particularly regarding optimal design and similar aspects.

Yes, Neal. That commentary out there is simply not based in fact. At the end of the day, Diamondback is completing these wells as quickly as anyone in the basin, utilizing two pads simultaneously with these simultaneous frac operations. Our supply chain is strong, and we are not at a disadvantage due to our size and scale. Some of the commentary likely stems from others struggling with broader cost structures that do not align with Diamondback's cost structure. The discussion often shifts toward size and scale because it's challenging to explain why others may perform worse when we can operate so much more efficiently and quickly. Honestly, I think you should ask those making those comments why they hold that view because, from the perspective of our shareholders, that is certainly not what we're experiencing or hearing.

Our next question will come from the line of Nitin Kumar from Wells Fargo.

I would like to revisit the whole concept of industry consolidation. A lot of your peers in their commentary, not only mentioned scale, but talked about just maybe a little bit of a tough environment to operate in. Your comments suggest a bit of optimism knowing that you don't have a crystal ball, just kind of maybe talk about your macro view from here and what you're seeing that gives you the confidence to go it alone?

There are definitely some significant challenges in the commodity market at the moment. We face uncertainty due to potential election outcomes and policy changes that could arise with a new administration. The ongoing struggle with COVID and the timeline for vaccine availability also impacts the recovery in supply and demand. Additionally, we have the upcoming OPEC+ meeting in December, which will address whether to continue or ease production cuts, along with a persistent global inventory surplus. While these macroeconomic factors are beyond our control, we will continue to focus on our cost structure and execution of our development plan. We are committed to maintaining our base dividend and enhancing our shareholder returns as commodity prices improve. We have already tackled our debt situation effectively. To be clear, 2020 has been a globally disruptive event, impacting not just the general public but our industry as well. Currently, we are confident in our business strategy and our capacity to implement it successfully. Furthermore, we are prepared to adjust our approach to preserve capital if conditions worsen. I have every reason to remain confident, despite the uncertainties in commodity prices. I trust the team at Diamondback and believe in the transparent communication we maintain with our shareholders regarding our objectives.

Yes. And Nitin, this business is not easy right now. There's no denying that, but that doesn't mean we're going to capitulate at the bottom of the cycle. I think Travis said it in his prepared remarks that we're not going to make a rash decision at the bottom of the cycle. Anything that happens means you have to get better, not necessarily bigger, to ride out of storm. This is not an easy business. We have plenty of our production hedged on the downside in 2021, and as Travis said, if things get worse, we'll have to make the tough decisions like we have already in 2020.

Look, Nitin, just one other point. At the bottom of the cycle, which I don't know if we're completely at the bottom of the cycle now, but even as bad as things have been in 2020, Diamondback is still a profitable company. We generated $153 million worth of free cash flow in the third quarter. We're paying our base dividend, which is yielding above the S&P 500, and we're reducing debt at the bottom of this cycle. If we can accomplish all of those things at the bottom of the cycle, think about what the world is going to look like for our shareholders as we start coming out on the other side of the cycle, which we know is inevitable, and we know that oil prices will increase in the future. We just don't know when. But if we're profitable like this at the very bottom of the cycle, then we're good.

I appreciate those comments. And certainly, it's a tough market, but you've done a great job. Maybe turning to that great job for a second here. Every quarter, you report slightly better drilling and completion costs. You're down 30% from just a year ago. In 2021, you have about 110 to 140 DUCs to help those capital efficiencies. But at what point in '21 do you think you need to add costs? And more importantly, what do you think that might do to your drilling and completion costs at that point?

Yes. I mean, there's no real sign that there's upward pressure on drilling and completion costs today. Certainly, Nitin, if we got to 2021, we will not guide to all-time low well costs, and we do have about a 50 DUC tailwind helping us out in 2021. That'll be a nice benefit to us. Overall, what we focus on is how many of these cost savings are permanent versus temporary. A good amount of these cost savings have been temporary, but we have learned a lot in terms of drilling design in the Delaware Basin and completion design in the Midland Basin with the simul-frac crews. We're going to keep those savings for the long term. While we're not counting on service prices increasing anytime soon, we recognize those guys are dealing with a very tough down cycle just as we are. At some point, service costs will go up, but that would probably coincide with higher commodity prices.

Our next question will come from the line of Derek Whitfield from Stifel.

Kaes, perhaps staying with you on your cost comments. Could you comment on how much of the drilling and completion improvement between '19 and current is structural versus market?

Yes. I mean, I'd say in the Delaware Basin, probably 50% is structural and 50% market. On the Midland Basin side, I'd say probably one-third is structural and two-thirds is market. We've already been pretty low on the cost curve, if not the lowest in the Midland Basin going into this downturn, and we have made some improvements with simul-frac and some cementing technology that we're implementing. The Delaware has been where we've made significant progress. We drilled a second Bone Spring well in under 10 days, a 10,000-foot well in under 10 days in Pecos County. I think our first wells in that area were 30-plus consistently. Those are the savings that will accrue to our shareholders long term. We focus on those rather than picking up the phone and reducing the service costs.

Understood. Shifting to your 2021 outlook, would it be fair to assume there could be a downward bias in your maintenance capital projections for 2021 as we walk this equation forward in time with the significant reductions in capital costs you've achieved to date and the macro backdrop that will likely not change for at least through the first half of next year?

Yes. But I think, Derek, the conversation needs to be about whether maintenance capital is the right scenario. If we stay in the mid-$30s and we get closer to our corporate breakeven, then the discussion needs to turn to whether we're generating positive NPV for our shareholders at those prices. Certainly, there are a lot of headwinds on the commodity side, and we're going to keep that 25% to 35% range out there, and we've kept it out there just due to the uncertainty rather than lowering it or changing it through this year.

Derrick, I just wanted to follow-up on some of the comments Kaes made about those permanent cost savings, 50% in Delaware and one-third in the Midland Basin. You shouldn't lose sight of the point that those are structural cost improvements. It's already the lowest or the best-in-class in those execution measures. It is not a casual exercise from our operations organization to drive costs out when they're already leading. I'm just really proud of what they've been able to accomplish.

Our next question will come from the line of Asit Sen from Bank of America.

Scope 1 emission reduction of over 50% year-over-year was pretty significant and impressive. Just wondering what your plans are on emissions going forward? Are the lower hanging fruits already been addressed? And how are you thinking about handling the policy change with the potential new administration and how you plan to navigate the regulatory framework that looks like it's changing?

I'll let Travis address regulatory matters after I clarify one point. Flaring has decreased by a little over 50% year-to-date. Flaring accounts for about 50% to 60% of our Scope 1 emissions. In terms of overall Scope 1 emissions, a reduction of approximately 25% to 35% in 2020 compared to 2019 seems more realistic. We have made advancements in our sustainability report regarding our targets, and we will likely announce long-term targets, spanning four to five years, for all the key metrics related to our environmental scorecard introduced this year. This is a collaborative effort with our midstream operator to reduce flaring overall. Additionally, we expect to benefit from lower activity levels compared to previous years, which reduces the portion of those Scope 1 emissions.

As a general statement, Asit, American energy producers have an important role in meeting the challenge of global climate change. We believe that climate policy must facilitate meaningful greenhouse gas emissions reductions but it must also balance economic, environmental, and energy security needs. We must promote innovative solutions to this climate challenge. As Kaes highlighted, this year, we adopted emissions targets as part of our executive compensation plan. Uniquely, all of our employees, 737 employees of Diamondback, share in that same bonus plan. Those environmental measures are part of their cash bonus. While we've not finalized incentive compensation for 2021, emissions targets will continue to be included. We're likely to set multiyear emissions reduction targets. I hope all energy producers can take this as a challenge and take a stand on what it is that we're trying to accomplish. We have an environmental and social license to operate in the areas we live and work, and Diamondback is trying to take a leadership position in that. Getting big doesn't have to be the case to accomplish our goals; we're doing it with our current scale. Our flaring from this time a year ago, even year-to-date, we're down 50-plus percent. From this time a year ago, we're down almost 75%. We've done what we needed to do, and we'll continue to lean into that until we've eliminated all routine flaring. We expect that to be sooner rather than later as long as we can work collaboratively with our midstream providers.

Appreciate that, Travis. And on the cycle, you talked about a tough down cycle that we are facing right now. Yet, you talked about an inevitable upcycle. What gives you the confidence in an upcycle? Just want to get your medium-term thoughts on the industry.

There are a few points to mention. According to various energy experts, the demand for energy from liquid hydrocarbons will persist for many years. The global population is still growing, and while there is a push for energy transition, we anticipate that supply and demand will eventually find balance. When that happens, commodity prices are expected to rise. While I can't predict the exact timing, I believe it may happen sooner than later. We are prepared to navigate this challenging environment, and we will prioritize the interests of our shareholders. I remain optimistic about long-term commodity prices due to the fundamentals of supply and demand.

Our next question will come from the line of Scott Gruber from Citi Group.

So you guys have completed a few simul-frac wells now. What level of savings are you realizing on the simul-fracs wells? And is there any incremental benefit still coming from simul-frac in your D&C figures? Or is that fully incorporated as we sit now?

Yes, Scott. I mean, it's fully baked into our leading-edge Midland well cost, which we put at $4.50 a foot. I think we are continuing to push the envelope on simul-frac. Recently in the third quarter, we completed two pads, separate well pads at the same time with the simul-frac crew, and those pads are about 1,000 feet apart. That's a pretty engineering feat from the team. Overall, it can get more efficient. We're completing about 3,300 lateral feet a day. Some days, we're getting upwards of 4,000 lateral feet a day. As those crews get more efficient, we'll continue to push the envelope there. The ancillary benefit is how quickly you can get into an area with existing production, complete a large pad, and get out of that particular area so that your watered out production is watered out for a shorter period of time. It's an unseen efficiency, but something that has been a positive rate of change for us since implementing the simul-frac crews. On the cost side, we estimate it's about $25 or $30 a foot of savings per well on the completion side.

Got it. So obviously, a lot of operational savings. Do you see any benefit on well performance in aggregate from the two wells given the creation of two side-by-side fracture networks at the same time?

It's certainly fair to assume that you're completing a larger tank at the same time and therefore not having as large a parent-child effect. I can't put a number on it, but more wells completed at the same time is better for the reservoir. If you have the infrastructure and facilities in place, you're not spending large dollars there. Then it's a logical path forward.

I'll tell you, Scott, the other kind of knock-on effect of that is that the modeling that we have to do, which has gotten more and more complex over the years, is what we call the watered-out effect. Because we're completing these wells so much faster, almost twice as fast, that watered-out effect has really been positively impacted in terms of its length and duration and its overall impact because we're getting on and off these wells so much faster. Not something we really contemplated when we started simul-frac, but we've seen the benefits of that now.

Our next question will come from the line of Jeffrey Grampp from Northland Capital.

Curious on the dividend front, it seems like given the free cash flow that you guys are projecting next year, certainly fundable at low prices and seems safe. So how are you guys assessing the right time to maybe look at growing that? It seems like, Travis, as you pointed out, the yield on it is obviously very competitive. So perhaps that's something that needs to get rectified organically before looking at dividend growth? Just your thoughts there would be great.

Yes, that's an important point I made earlier: our yield is already over 5%. Our board is dedicated to maintaining that dividend, which is the main component of our shareholder return program. We discuss it at least every quarter, if not more often. I want to emphasize that our current strategy is to maintain the base dividend at a level above the S&P 500 yield and to focus on reducing debt. As commodity prices increase, we will have opportunities to utilize excess free cash flow beyond the dividend and debt reduction.

Yes. It's important to look back at earlier this year and the conviction it took to maintain that dividend through the down cycle or the worst of the down cycle. It was not an easy decision, particularly after we doubled the dividend in February. I keep hearing about forward return of capital and what people are going to do. Looking at our history and what we've leaned into to maintain that dividend, while others have either suspended theirs, cut it or even sold their companies should be reviewed by our shareholders.

Yes. That's a good point, Kaes. Appreciate that. My follow-up, looking at the slide five here on the new deck, you guys are suggesting, I think, 34 to 64 completions in Q4. I know that's just kind of implied based on the guide. So just wondering if you guys can give us an indication of where you expect Q4 completions to fall in that range? And maybe it's kind of a related point, in the maintenance world for '21, how many fewer wells do you guys think get completed in '21 versus '20?

Yes. I think overall, Q4 is probably at the midpoint, if not a bit above for completions now. It is dependent upon when those wells are turned to production. You do have eight days of holidays at the end of the year, so there could be some noise in the amount of wells. Certainly, the midpoint-ish is a good guide. In 2021, I do think we are moving to more Midland Basin. You need more wells to keep production flat in the Midland Basin than you do in the Delaware. Those wells cost significantly less but produce less in that year. So I think a range around the upper half of what we put this year is likely, but we're still doing all the engineering and high grading the development plan to get those numbers out.

Our next question will come from Scott Hanold from RBC Capital Markets.

Just a couple of follow-ups that are more specific to some of the Q&A that already occurred. You talked a few times about seeing some better well performance recently. Can you quantify some of that and tell us how you feel confident that that's what you expect going forward?

Yes, Scott. We look at production every day, and we look at individual well results every day. We're seeing some really good pads that are coming on in the Midland Basin and outperforming our expectations, as well as a few pads in the Delaware, particularly in the Vermejo area, that are also exceeding our expectations. While I'm not going to give a number out, I think the message is increased confidence. 2020 has been a tough year. We were running 20 rigs in Q1 and completed a lot of wells in the Southern Delaware and then had to curtail a lot of wells in Q2. We're starting to finally see the benefits of that reallocated capital plan in Q3 and Q4 and expect that to continue into 2021.

Okay. Fair enough. And then going back, obviously, to the plan in 2020 and maybe beyond, but you talk about prioritizing the dividend and debt pay down. Can you walk us through what oil price or what amount of free cash flow gets you guys to look at things like a shareholder return or growth? Or how does that conversation happen? I know it feels like we're a long way from there, but certainly, it's relevant to think about where is that point that it comes to do one or both of those? And how does that work?

Well, we need to clarify that it will be an increased shareholder return, right? Because we already are returning capital to shareholders in the form of our base dividend, which has the highest yield in the space. This gets lost in the shuffle of some of this analyst commentary today. We have to see a demand recovery and some stability in the forward outlook. There are about as many things working against us as an industry as they ever have been. Once those get clarity, let's say we're safely into the high $40s WTI with a strip that is comfortably in that range, then I think we can have that conversation. But I don't want to have that conversation at $37 going to $38 today.

Is there a leverage level that you need to see first?

No. Because leverage is a function of both EBITDA and gross debt. As long as we're comfortable that we are consistently reducing gross debt, the additional return of capital is not mutually exclusive to our ability to reduce gross debt. The only thing that is off the table is significant growth. Those days are probably behind us. We've been a bigger grower than anybody in this industry. But shareholders want cash; they want it now. Therefore, we're going to do that through our growing base dividend and also reduce the leverage issue to reduce our equity cost of capital and therefore, improve the stock price.

And our next question will come from Charles Meade from Johnson Rice.

Scott kind of front-ran my question a little bit there, but I will try to push it a little bit further by looking at your Slide 6 in your presentation. The message I get is that you guys wouldn't add any growth-directed capital expenditure until we were over $55, but then it's on the table over $55 WTI. Is that the right interpretation? Or is there something else there?

Yes, Charles. That would be a really good day versus where we've been over the last nine months. I'd be happy to have that conversation if we start to see a 5 handle on crude. A lot of companies have made a pledge that they're not going to grow over a certain amount. It's hard to put this industry in a box, given how volatile it is. That being said, growth is off the table for us until we see significantly higher oil prices. Then that growth will be muted and somewhere in that single-digit range rather than the high double digits we had in the past.

The more germane question should be, how does that look at a $36 world as opposed to what we're going to do when oil is $55 a barrel?

Right, Travis. I appreciate the points you've raised in your comments. I have a broader question that resonates with familiar themes. When I speak with individuals outside of this industry, one common criticism we encounter is the question of maintenance capital plans. They wonder why, if investing to grow volumes isn't appealing, we would choose to invest just to maintain our current volumes. What additional insights can you provide to clarify the importance of keeping production stable under these circumstances?

Yes, you're asking an important question. The key issue is what kind of returns you're getting from your capital program. If it's maintenance capital, what returns can you expect at a $35 or $36 barrel price? If the returns to investors are minimal or non-existent, then why maintain flat volumes? That's the point I wanted to highlight in my prepared remarks. The discussion shouldn't focus on growth; instead, it should consider if we stay around $35 a barrel, how much and how quickly you need to reduce capital and the decline in volume.

And on top of that, what's been lost is, what is the rate of return of that program? I think Travis said that, and are you breaking even? Or are you actually returning cash? I look forward to other companies answering that question in this commodity price environment.

Our next question will come from the line of Brian Singer from Goldman Sachs.

I wanted to follow-up on the topic of decline rates. It's come up a couple of times on the call, but I wanted to see, especially given that it was brought up as a reason for consolidation by another company. How do you see your decline rates this year and in the maintenance capital plan next year on an oil and BOE basis, and your confidence in the ability to execute a free cash capital returns model from the perspective of a Permian pure play?

Yes, Brian, it's a very good question. It's topical, right? Companies have reasons for why they do things. I'm only going to speak about Diamondback. Slowing down as much as we have is reducing our base decline. Our base decline is going to go down from high $30s oil to mid-$30s oil in 2021. BOE is slightly below that. A really smart investor told me, as long as you're running the treadmill at the right pace and generating free cash above that capital, this business model can work. As long as we're setting that target and ensuring that we're not moving activity levels up and down consistently while still generating free cash, people will pay attention to that and prove that you can return capital and generate sufficient returns to be successful in U.S. shale.

It's difficult to look at an acquisition or merger and try to justify it on decline rate. I get the math behind that. Kaes articulated the way we think about decline rates, but it's unlikely. I'll stop there.

Our next question will come from the line of David Amoss from Heikkinen Energy.

The question I had was, we're thinking about the Permian being overpiped and just the gross volumes that you all are producing. Clearly, estimates would be about 240,000 or somewhere would be our estimate versus your 175,000 commitment. Can you just give us what your gross volumes are for the third quarter so we can start thinking through the whole industry as we get into '21?

Yes, David, that's a good question. We're probably in the 220,000 to 230,000 gross range from a production perspective. We are trying to avoid cash outflows for take-or-pay commitments and marketing arrangements. Certainly, the Permian is overpiped today. I think we see these commitments and our space on the pipelines as long-term insurance policies. The volatility in this industry has been dramatic. There are some phone calls we could make in March and April to ensure our barrels are going to move and exit the water or hit floating storage because of our commitments to those pipelines. The legacy pipelines need to reduce their tariffs before ours, which are lower tariff pipes in the basin.

Last call will come from the line of Jeanine Wai from Barclays.

My first question is on the maintenance capital expenditure. My second question is on spacing. For the maintenance capital expenditure, in terms of just trying to understand all the moving pieces here, you've done a really great job at meaningfully reducing well costs year-over-year. And I think I heard you say earlier in the call that midstream infrastructure capex would be down about 50% as well next year. So in terms of the workovers, I think before you mentioned that you reduced the number of workover rigs by as much as 80% at one point to respond to prices. Can you just comment on how workover costs may trend next year at different oil prices? And how are these costs split between capex and operating expense?

Yes, Jeanine. There is a very distinct difference between workover rigs used for operating expense and what we call capital workovers, which is basically converting your electric submersible pumps to their final form of lift, usually a rod pump. We do spend a little bit of capital, $0.25 million or so per well that goes to its final form of lift, and that will be part of the 2021 budget. It's never been a significant issue for us; a big piece of our budget as we have always completed more wells than 10 years prior and the capital budget continues to expand. Heading into 2021, a few years ago, we completed about 300 wells pro forma, and those wells in 2021 will move to their final form of lift. In terms of spacing, in the Midland Basin, where you have more economic zones that are getting co-developed, we're getting smarter about both vertical and horizontal spacing, and those spacing assumptions vary versus Howard County versus Northern Martin County versus Midland County. We're continuing to refine our development program. Secondary zones will be spaced wider than primary zones with the highest rate of return. In the Delaware Basin, it's less of an issue because you have less zones that are economic or comparable that compete for capital today. We're refining spacing, not significantly widening it, but secondary zones should get wider as oil prices go lower.

I'm not showing any further questions at this time. I'd like to turn the call back over to Travis Stice, CEO, for any closing remarks.

Thank you. It's another milestone made today, it's election day. I can't help but be reminded that one of the enduring legacies our founding fathers left us was a system for a peaceful transfer of power. I pray for our country that we can remain calm in the upcoming days and weeks as we move through this process of electing our next leader. Thank you, everyone, for listening in today and for the good questions. If you've got any additional questions or follow-ups, just reach out to us using the contact information provided. Thank you, and stay well.

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