Welcome to the Diamondback Energy third quarter 2020 earnings conference call. At this time, all participant lines are on a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one on your telephone. Please be advised that today's conference is being recorded. If you require any further assistance, please press star zero. I would now like to hand the conference to your speaker today, Adam Lawlis, Vice President, 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. Welcome to Diamondback's third quarter earnings call. Diamondback continued with our trend of cost reductions in the third quarter, with LOE and G&A remaining near all-time lows and capital cost per lateral foot continuing to decline to new records. Our drilling and completion operations continue to gain efficiencies, and current well costs are now 30% lower than 2019 levels in both the Midland and Delaware Basin. We're also beginning to see the benefits from high-grading our development program 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%-35% less capital than 2020, and 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 pricings 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 on 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 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 percent-of-proceeds contract to a fixed fee construct. 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.
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 changing 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. We do not need to increase our scale to further reduce our cost structure. We produce 300,000 barrels per day at the lowest cash and capital costs in the industry.
We also have an investment-grade balance sheet with a 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 bigger 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 an arbitrary number such as a level of production or 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. 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 accreted to the acquirer's shareholders, not the targets. Whether the transaction is an MOE 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, and 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.
Thank you. As a reminder, to ask a question, you will need to press star one on your telephone. To withdraw your question, just press the pound key. Please stand by while we compile the Q&A roster. Our first question will come from the line of Arun Jayaram from JPMorgan Chase. You may begin.
Good morning, Travis. It's clear from your commentary that you believe you have a 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 PV-17 valuation. Maybe just start with your thoughts on what you're seeing in the A&D market.
Well, let me just circle back to you re-emphasizing my point on scale. There's not a single service company that's calling us up and saying, "Hey, you're not big enough. We're not going to be able to do business with you." I think we've laid out a pretty good case for how you should think about Diamondback, in terms of size and scale and balance sheet and execution metrics. As it pertains to M&A, it's hard for me to forecast M&A. I think you got to go back and just focus on the words that I said. We're going to grow our asset base just like we've always done, only when we can show that we can drive shareholder value. That has been the same since in October of 2012 when we took the company public.
That's what we come in to work forward thinking about every day, is how can we drive shareholder value? If it comes through execution or it comes through M&A, that's what we'll do.
Great. 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. 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 as opposed to what Diamondback's legacy operation practice was ESP. Now we still have a lot of ESPs in the ground. We've been making a fundamental shift in going from ESPs to gas lift. We're seeing a significant reduction in cost savings, and at the same time, we're not seeing any detrimental impact on performance.
Something we're really excited about, and if you just step all the way back from it, these ESPs, while it's pretty easy just to crank the wrist head up or down in response to volume needs, at the end of the day, you're hanging an electric motor in water a mile and a half in the ground with an extension cord, and there's nothing but bad things can happen in that scenario. They're still going to be a part of our operating plan, ESPs will be, but we're really excited about some of the leading-edge technologies we're deploying with gas lift. Listen, just on the expense side, our focus has always been to be the lowest cost operator in the Permian Basin.
We've got an organization that understands that for every penny that we save in costs, whether it's LOE or G&A, that translates to $1 million of cash flow that we can return to shareholders or whatever. 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.
Yep. It shows in the numbers. Thanks a lot.
Thank you, Arun.
Thank you. Our next question will come from the line of David Deckelbaum from Cowen. You may begin.
Morning, Travis and Kaes. Thanks for taking my questions today.
Thanks, David.
Curious, you referenced the high grading benefits that you're seeing right now in execution of this 2020 plan. Can you talk about how you see high grading influencing the 2021 plan? You sort of pegged this free cash flow at $525 million at $40. Are you seeing further benefits going into 2021 from high grading? How long, I guess, as you think about, you emphasize the scale that Diamondback has. How long do you think you could sustain, at a maintenance level, this high-grader program for?
Yeah, 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.
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. All that results in a little more capital efficiency, and I think a nice setup from a well result rate of change story heading into next year. On your second comment, 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 multi-year period. I don't know what the exact number of years is.
It depends what happens with the oil price and activity. 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 in looking at this kind of 2/3 Midland Basin, 1/3 Delaware or 0.75, 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. 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. Just my follow-up just on that 2021 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?
Yeah, David. You know what? I think we've said that midstream 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 that we had in 2019. All of that's coming down. It allows us to spend more capital on the drill bit, versus the ancillary stuff that does have a benefit and does reduce our cost structure. 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. Looking forward to that continuing to decrease. Then, as you mentioned 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.
Hey, 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, and the slower we go, the more towards maintenance capital we and the industry goes. That just extends whatever the perception of inventory life is. That just extends it out because we're just not plowing through it at the same pace we were last year when we were running 20+ rigs. I hope that clarifies that a little bit.
Indeed, Travis, thank you. Thank you, Kaes.
Thank you. Our next question will come from the line of Gail Nicholson from Stephens. You may begin.
Good morning. You guys are entering a phase of very attractive free cash generation at 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?
Yeah, 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 do 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, I think 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 got to have cash on the balance sheet to be able to handle those, and I think our plan is to make sure we have a little more cushion and rely less on bank financing overall.
Great. Looking at your free cash flow scenario on page seven 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. I was just curious what Brent-WTI differential you're using for that 95% WTI realization.
Yeah. We're using $3 there. That ratio is a little tighter right now, and 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 pipelines to get to the Gulf Coast. Should that Brent-WTI spread widen, we'll naturally benefit. I think on our Brent realized pricing, we're kind of realizing a Brent less $5 or $6. For the rest, you're realizing an MEH price or a Midland direct price for now.
Okay, great. Thank you.
Thank you, Gail.
Our next question comes from the line of Neal Dingmann from Truist Securities. You may begin.
Morning. Travis, for you and Kaes, you were talking about the productivity and your confidence. I'm just wondering, would you all say the largest driver of this productivity, is it more driven by the asset location or just operational efficiencies, or is it just kind of all the above and kind of what gives you that confidence it sounds like you have now for the next few quarters?
Yeah, I think it's all the above, Neal. I don't think anyone's ever questioned Diamondback's cost structure or ability to execute on the capital side. Overall, I do think the Street does look at these curves intently, and I think we're, particularly on the Midland Basin side, 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. Just follow up. Travis, what you were saying on scale, do you believe we continue to hear a lot of chatter that you have to have more scale? Is that more, I don't know? I guess I've heard folks say that about turning out more optimal pads, having more optimal areas in plays. Maybe you could comment around that. It seems like there's still a lot of chatter around that, I just want to hear maybe more of your color around how you view you all versus sort of the peers when it comes to, again, maybe some others might have a bit more scale, but when it comes to optimal design and those sort of things.
Yeah. Neal, listen. That commentary that's out there is just out. It's not based on fact. At the end of the day, Diamondback, we're completing these wells as fast as anybody in the basin with two pads at the same time with these simul-frac operations.
All of our supply chain is tight. We're not at any disadvantage based on size and scale. I think some of the commentary is because people are struggling with why their cost structure is disconnected from Diamondback's cost structure. The commentary navigates towards size and scale because it's difficult to point to why Diamondback can do it so much cheaper and so much faster. I don't know. You need to ask the people that are making those comments why they're making those comments, because it's certainly, from our shareholders' perspectives, that's not what we're seeing nor hearing.
Very good. Thanks for the details. Thanks, guys.
Thanks, Neal.
Our next question comes from the line of Nitin Kumar from Wells Fargo. Nitin?
Good morning, Travis and Kaes. Thanks for taking my question. I want 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's certainly some significant headwinds on the commodity space right now. We've got the election uncertainty and looming policy changes if there's an administration change. We've got COVID, we're still struggling to how to contain that, and is there going to be a vaccine anytime soon, and what does that mean to the supply-demand recovery? We've got OPEC+ meeting in December to talk about whether they maintain cuts or start easing those cuts. We've got a global inventory overhang that's still there. All of those are macro issues that I can't control and we can't influence. What we can do is continue to focus on the cost structure and how we execute on our development plan, how we demonstrate confidence in our base dividend, and how in an improving commodity price world, we take advantage of increasing our shareholder-friendly returns program.
We're addressing our debt issue right now. Look, this 2020, let's be clear, this has been a global apocalyptic event. Not only for citizens at large, but certainly for our industry. We're at a point now where we feel very confident in the business plan that we have in place. We feel very confident in our ability to execute and consistently deliver on that business plan. We also feel like we're enough of an adult in the way that we look at things. If they get worse from here, we'll change our behaviors, and we'll slow down and preserve capital. There's nothing for me not to be confident in.
There is uncertainty ahead of us in the commodity price world, but I'm confident in the people we have at Diamondback, and I'm confident in the communication we have with our shareholders about what it is we're trying to accomplish.
Yeah. Nitin, this business is not easy right now. There's no denying 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 a storm. This is not an easy business. We have plenty of our production hedged on the downside in 2021. 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's going to look like for our shareholders as we start coming out of the other side of this cycle, which we know is inevitable, and we know that oil price will increase in the future. We just don't know when.
If we're profitable like this at the very bottom of the cycle, we're on the other side. We're good.
Thanks, guys. I appreciate those comments. 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 D&C costs. You're down 30% from just a year ago. In 2021, you have about 110 to 140 DUCs to help those capital efficiencies. At what point in 2021 do you think you need to add costs? More importantly, what do you think that might do to your D&C costs at that point?
Yeah. There's no real sign that there's upward pressure on D&C costs today. Certainly Nitin, if we guide to 2021, we're not going to guide to all-time low well costs. We do have about a 50 DUC tailwind helping us out in 2021. That'll be a nice benefit to us. I think overall, what we focus on is how many of these cost savings are permanent versus temporary. While a good amount of these cost savings have been temporary, we have learned a lot in terms of drilling design in the Delaware Basin, as well as completion design in the Midland Basin with the simul-frac crews that 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 and at some point, service costs will go up, but that would probably coincide with higher commodity prices.
Great. Thanks for the answers this morning, guys.
Thank you, Nitin.
Thank you. Our next question will come from the line of Derrick Whitfield from Stifel. You may begin.
Thanks, and good morning, all.
Hey. Good morning, Derrick.
Hey, Kaes, perhaps staying with you on your cost comments. Could you comment on how much of the D&C improvement between 2019 and current is structural versus market?
I'd say, in the Delaware Basin, probably 50% is structural and 50% market. On the Midland Basin side, I'd say probably 1/3 is structural and 2/3 is market. We'd 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's been where we've made significant progress. We drilled a second Bone Spring well in under 10 days, 10,000 ft well in under 10 days in Pecos County. I think our first wells in that area were 30+ consistently. Those are the savings that are going to accrue to our shareholders long term, and those are the things we focus on rather than the picking up the phone and reducing the service costs.
Understood. Then 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 likely will not change for at least the first half of next year?
I think, Derrick, the conversation needs to be is maintenance capital the right scenario? I think if we stay in the mid-30s, and we get closer to our corporate break even, I think the discussion needs to turn to are you generating positive NPV for your shareholders at those prices? Certainly, there's a lot of headwinds on the commodity side, and we're going to keep that 25%-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.
Hey, Derrick, I just wanted to follow up on some of the comments Kaes made about those permanent cost savings, 50% in Delaware and 1/3 in the Midland Basin. You shouldn't lose sight of the point that those are structural cost improvements on an operator that's already the lowest or the best in class in those execution measures. It's not a casual exercise from our operations organization to continue, when they're already leading, to drive costs out. I'm just really proud of what they've been able to accomplish.
Appreciate it and noted, Travis. Great update, and thanks again for your time, guys.
Thank you, Derrick.
Our next question will come from the line of Asit Sen from Bank of America. You may begin.
Thanks. Good morning. 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? How are you thinking about handling the policy change with a potential new administration and how you plan to navigate the regulatory framework that looks like it's changing?
Yeah. Asit, I'll let Travis handle regulatory after I clarify one thing. Flaring is down 50%, or sorry, a little over 50% year to date, and flaring makes up about 50% or 60% of our Scope 1 emissions. I think overall, Scope 1 probably down 25%-35% in 2020 versus 2019 is more of a realistic number. We have made progress in our sustainability report to put out targets. I think we'll probably next come out with long-term targets, four or five-year targets on all of the metrics that matter to our environmental scorecard, which we implemented this year. Overall, that's just a concerted effort between us and our midstream operators to reduce flaring overall, and I think we'll have a little bit of a tailwind as well with lower activity levels versus years prior, which makes up a smaller portion of those Scope 1 emissions.
Yeah, I think as a general statement, Asit, American energy producers, we've got an important role in meeting the challenge of global climate change. We believe that climate policy has got to facilitate meaningful greenhouse gas emissions reductions, but it's also, at the same time, got to balance economic, environmental, and energy security needs. We've got to promote innovation solutions to this climate challenge. As Kaes highlighted, this year we adopted emissions targets and as part of our executive compensation plan. We also, uniquely, all of our employees, 737 employees at Diamondback, they share in that same bonus plan. Those environmental measures are part of their cash bonus. I can also tell you while we've not finalized incentive comp for 2021, emissions targets are going to continue to be included in our comp plans, and we're likely to set multi-year emissions reduction targets.
Listen, I hope all the industry, I hope all of the energy producers can take this as a challenge to step forth and take a stand on what it is that we're trying to accomplish. We have an environmental and a social license to operate in the areas we live and work, and Diamondback, we're trying to stand up and take a leadership position in that. Again, just back to that scale comment, we're doing this. You don't have to be big to do this. We're doing it at our current scale. Getting big to accomplish environmental goals, again, we're proving that that's not the case. I think if you look at our flaring from this time a year ago, even the year to date, we're down 50 some odd 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. Travis, on the cycle, you talked about a tough down cycle that we're facing right now, and yet you talk about an inevitable upcycle. What gives you the confidence in an upcycle? Just want to get your medium-term thoughts on the industry.
Sure. There's a couple of things. Pick your energy expert forecaster. The world is going to continue to need energy from liquid hydrocarbons for many, many years to come. Our population is continuing to grow. We understand that there's going to be the world that's striving for energy transition, but in the near term, supply and demand is going to rebalance, and when it does, that's going to lead to the inevitable rise in commodity price. I don't know when that's going to occur, but I think it's probably going to occur sooner rather than later. We're positioned to, like I said, weather this storm, as brutal as it's been. We'll continue to do what's the best thing for our shareholders. I am constructive on commodity price long term because of the supply-demand fundamentals.
Appreciate the color. Thanks.
Thank you. Our next question comes from the line of Scott Gruber from Citigroup. You may begin.
Yes, good morning.
Hey, Scott.
You guys have completed a few simul-frac wells now. What level of savings are you realizing on the simul-frac wells? Is there any incremental benefits that'll come from simul-frac in your D&C figures, or is that fully incorporated as we sit now?
Yes, Scott, it's fully baked into our leading-edge Midland well cost, which we put D&C at $450 a foot. I think we are continuing to push the envelope on simul frac, and I think even recently in the third quarter, we completed two pads, separate well pads at the same time with the simul frac crew. Those pads were about 1,000 ft apart, so it was a pretty engineering feat from the team. Overall, certainly it can get more efficient. We're completing about 3,300 lateral feet a day. Some days we're getting up to upwards of 4,000 lateral feet a day. As those crews get more efficient, we'll continue to push the envelope there.
I also think 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. That'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. 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 of a parent-child effect. I can't put a number on it, we do agree that more wells completed at the same time is better for the reservoir. If you have the infrastructure and facilities in place where 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 water out effect. Because we're completing these wells so much faster, almost twice as fast, that water 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.
Gotcha. Appreciate the color. Thank you.
Thank you, Scott.
Thank you. Our next question comes from the line of Jeff Grampp from Northland Capital. You may begin.
Morning, guys.
Hi, Jeff.
Travis, 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. 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's obviously very competitive, so perhaps that's something that needs to get rectified organically before looking at dividend growth, or just your thoughts there would be great.
That's the reason I made that point earlier was the fact that our yield is already, what, over 5%. I'll just tell you that our board is committed to that dividend as the primary form of our shareholder return program, and we talk about it at least every quarter, if not more frequently than that. I've tried to be very clear what our strategy is right now. It's to pay that base dividend that. Right now it's above an S&P 500 yield, and reduced debt. As commodity price rises, well, then we have options to do things with excess free cash flow above the dividend and debt reduction.
Yeah. Jeff, I think 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. That 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. I think looking at our history and what we've leaned into in order to maintain that dividend, while others have either suspended theirs, cut it, or even sold their companies, should be reviewed by our shareholders.
Yep. Good point, Kaes. Appreciate that. For my follow-up, looking at slide five here on the new deck, you guys are suggesting, I think 34-64 completions in Q4. I know that's just kind of implied based on the guide. Just kind of wondering if you guys can give us kind of an indication of where you expect Q4 completions to fall in that range, and maybe as kind of a related point, in the maintenance world for 2021, how many fewer wells do you guys think get completed in 2021 versus 2020?
Yeah. I think overall Q4 is probably at the midpoint, if not a bit above for completions. 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, but certainly the midpoint-ish is a good guide. In 2021, I do think we are moving to more Midland Basin. You do need more wells to keep production flat in the Midland Basin than you do in the Delaware. Those wells cost significantly less, but they produce less in that particular year. I think a range around the upper half of what we put this year is likely. We're still doing all the engineering and high-grading The development plan to get those numbers out.
Got it. Really helpful, Kaes. I appreciate the time, guys.
Thank you, Jeff. Operator, next question.
Sorry about that. I was on mute. Scott Hanold from RBC Capital Markets, your line is open.
Yeah. Thanks. Just a couple 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?
Yeah, Scott, listen, we look at production every day, and we look at individual well results every day. What we're seeing is 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 messaging is increased confidence. 2020's been a tough year, where 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 the wells in Q2. I think 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. Then, going back obviously to the plan in 2020 and maybe beyond, but you talk about obviously 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 like growth, or how did that conversation happen? I know it feels like we're a long way from there, but certainly, it's a relevant kind of topic to think about. Where is that point that it comes to do one or both of those, and how does that work?
I think we need to clarify that it's 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. I think that gets lost in the shuffle of some of this analyst commentary today. I think, Scott, we got to see a demand recovery and some stability in the forward outlook. Right now, there's about as many things working against us as an industry as there ever have been. Once those get clarity and, 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. I don't want to have that conversation at $37 going to $38 today.
Yeah. Is there a leverage level that you need to see first?
No, because leverage is a function of both EBITDA and gross debt. I think as long as we're comfortable that we are reducing gross debt consistently, the additional return of capital is not mutually exclusive to our ability to reduce gross debt. I think the one thing that is off the table is significant growth, and those days are probably behind us. We've been as a bigger grower as anybody in this industry, but I think shareholders want cash and they want it now. Therefore, we're going to do that through our growing base dividend and also reducing the leverage issue to reduce our equity cost of capital and therefore improve the stock price.
Thank you.
Our next question comes from the line of Charles Meade from Johnson Rice. You may begin.
Good morning, Travis and Kaes. 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 six in your presentation. I just want to see if I'm interpreting this the right way. When I look at that graph you guys have for your investment framework on the left-hand part of the slide, to me, the message I get is that you guys wouldn't add any growth-directed CapEx 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?
Yeah, Charles, I mean, that'd be a really good day versus where we've been for the last nine months. I'd be happy to have that conversation if we start to see a five handle on crude. I think you've seen a lot of companies make a pledge that they're not going to grow over a certain amount. I think it's hard to put this industry in a box given how volatile it is. I can say today that growth is off the table for us until we see significantly higher oil prices. Then that growth will be muted in somewhere in that single-digit range rather than the low double digits or even teens that we've had in the past.
Yeah, I think the more germane question should be asked of those operators that are touting this future 2022 and beyond return to shareholders. I think the more important question should be, how does that look in a $36 world, as opposed to what are we going to do when oil's $55 a barrel?
Right. Yeah, Travis, I've appreciated the themes you've tried to amplify in your comments on that front. I think this is a big picture question, more familiar territory, but when I talk to people who aren't involved in this space, one of the pushbacks I get is they say, "Well, these maintenance CapEx plans don't really seem to make sense. If it's not attractive to invest and grow your volumes, why do you want to invest to keep your volumes flat?" What are the other pieces of the picture that you'd put out there to try to answer that question about why it's important to keep production flat if you can?
Yeah, just generally, I think you're raising the right question. The right question should be, what kind of returns are you generating on your capital program? If it's maintenance capital, what kind of returns are you generating at $35, $36 a barrel? If the answer is little to no returns to your investors, then why would you even keep volumes flat? That's what I tried to raise. I tried to raise that point in my prepared remarks. Look, the conversation should not be about growth. It should be that if we remain range-bound around $35 a barrel, how much and how fast do you cut capital and let volumes decline?
On top of that, what's been lost is what is the rate of return of that program. I think Travis said that. Are you breaking even or are you actually returning cash? I look forward to other companies answering that question in this commodity price environment.
All right. Thanks, guys. Appreciate it.
Thanks, Charles.
Thank you. Our next question comes from the line of Brian Singer from Goldman Sachs. You may begin.
Thank you. Good morning. Wanted to follow up on the topic of decline rates. It's come up a couple times on the call. I wanted to see, especially given that it was brought up as a reason for consolidation by another company, how you see your decline rates this year and in the maintenance capital plan next year on a 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.
Yeah, Brian, it's a very good question. It's very topical, right? I think companies have reasons for why they do things. I'm only going to speak about Diamondback, and I know that slowing down as much as we have is reducing our base decline. Our base decline's 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 making sure that we're not moving activity levels up, down, all around consistently, and consistently generating free cash, I think people are going to pay attention to that and prove that you can return capital and generate sufficient returns to be successful in U.S. shale.
It's just really difficult to look at an acquisition or a merger and try to justify it on decline rates. I get the math behind that, but I think Kaes articulated the way we think about decline rates, but it's unlikely with it. I'll stop there.
Great. Thanks. My follow-up is also a little bit on the M&A discussion, but more from a Diamondback look-back perspective. You've done M&A before. Energen, I think about two years ago, it closed or so, maybe a little bit less than that. I wondered, as you look back and you highlighted a little bit some of the benefits from ESPs and some learnings, but how you look within the framework that you set for what makes good M&A to the buyer, and how Energen or the other deals you've done have impacted Diamondback today, and then what you see as the pitfalls that you've learned that maybe may or may not be applicable for others?
Brian, we spent a lot of time post-Energen acquisition to articulate what the synergies were and what our progress was on delivering on those. We created the industry's first synergy scorecard so that our investors could hold us accountable on a quarterly basis on how we delivered on those things. Look, we delivered on every one of those things, including becoming investment-grade a full year ahead of time, dollar amount. From the things that we could control, all of these acquisitions have worked out well for us. The oil price assumptions that we made at the time of the acquisitions, have those played out? Well, certainly not in 2020. Have the development plans been adjusted in some cases because of learnings? Yes, that means accelerated and decelerated in some cases.
Look, at the end of the day, we've got to deliver on what we can control. I think we've been able to do that, and we're still demonstrating that today. I think as we've done our look backs and we realized that commodity price moved away from us on some of those things, we have talked about our hedging strategy relative to acquisitions. Should we take a portion of commodity price risk off the table at acquisition time by doing hedges? Other than that, the operational measures, the cost-saving measures, the G&A and LOE reductions, those things, we've delivered on all of those, and you can go back just a couple of quarters and look at what we call our synergy scorecard and our accountability to our shareholders for delivering on those.
Great. Thank you very much.
I think, listen, bottom line, Brian, if you can do it, we deliver on it. If you can't, you come up with all these different kind of excuses. We hold ourselves accountable for what we promised our shareholders, and we'll always do that on a go-forward basis as well.
Thanks, Travis.
Our next question comes from the line of Leo Mariani from KeyBanc. You may begin.
Hey, guys. I wanted to follow up a little bit on the high grading comment. I think if I wind the clock back a little bit to 2019, you guys had basically said that we will be working in some lower IRR zones into our development plan to make sure those resources were properly captured over time and not left behind. I just wanted to get a sense if your recent comments about high grading indicated that maybe you're moving away from doing some of that in the near term, just given the lower oil price environment that we're in here.
Leo, I think you have to look at that as a margin. I certainly don't think we're abandoning co-development at all. We do think developing more zones together at the same time, should those zones be economic at today, $40 a barrel, they're going to get developed. Spacing assumptions between zones can change and should widen as commodity prices weaken. I think the high grading is really more about the consistency and deliverability of Midland Basin rock at low cost. We were shifting to the Midland Basin before this downturn, but the downturn certainly accelerated it and moved us more to a 2/3, 1/3 or 70-30 Midland Basin, Delaware Basin than a 55-45 or 60-40.
Okay. That's helpful. I guess just to follow up on your maintenance CapEx range for next year, you guys certainly seem confident you can execute this at a 25%- 35% lower budget. Just wanted to get a little bit of clarity on what gets you the 25% lower versus the 35% lower. Is it really just about well costs? Obviously, you guys articulated that leading edge well costs have come down quite a bit here recently.
Yeah, I think it's well costs and number of wells completed. While we're not thinking about it today, you do need to plan for 2022 in 2021, particularly from a rig count perspective. Looking to keep that guidance wide today and narrow it as we finalize the development plan over the next few months.
Thanks, guys.
Thank you, Leo.
Thank you. Our next question comes from the line of Jeoffrey Lambujon from Tudor, Pickering, Holt. You may begin.
Good morning. Thanks for taking my question. Just one from me on the corporate structure specific to Rattler. Just looking at relative valuation between Diamondback and Rattler, just curious if there's an opportunity there or any consideration internally to potentially pull that structure in.
Yeah, Jeff, we're certainly looking at it. Rattler is a new company in its infancy, and I think this ties to our commentary on M&A. We're not looking to do anything rash at the bottom of the cycle. Certainly Rattler's gone through a large phase of growth through all of the equity method investments. Those are behind us. The business is generating free cash. It's not getting a lot of credit from the market, but I think we've studied the GP/LP relationships throughout E&P land very closely, and I think for us, we see our LPs as partners and therefore aren't going to make a rash decision, even though the two multiples are trading on top of each other today.
Appreciate it.
Thank you, Jeff.
Thanks, Jeff.
Thank you. Our next question comes from the line of David Heikkinen from Heikkinen Energy. You may begin.
My grandpa would be really proud of that Heikkinen pronunciation of our name. That's actually correct. The question I had was, we're thinking about Permian being over-piped and just the gross volumes that you all are producing clearly will be 240 or somewhere would be our estimate versus your 175 commitment. As a whole, can you just give us what your gross volumes are for the third quarter? We can start thinking through the whole industry, as we get into 2021.
Yeah. David, that's a good question. We're probably in the 220-230 gross range, from a production perspective. Not having to pay take or pay commitments, which I think, we set up those contracts in a way that half of our pipeline space is take or pay, and the other half is from the acreage dedication. I'm trying to avoid cash outflows for take or pay commitments and marketing arrangements. Certainly, the Permian's over-piped today. I think we see these commitments and our space on the pipelines as long-term insurance policies. While Brent, Midland has gone against us for the last couple of quarters, the volatility in this industry has been dramatic.
There were some phone calls that we could make in March and April to know that our barrels are going to move and exit the water or hit floating storage because of our commitments to those pipelines. Certainly over-piped, but I think the legacy pipelines need to reduce their tariffs before ours that we're on, which are the lower tariff pipes in the basin, get hit more.
Thinking about sub $1 tariffs, is that reasonable for some of the new recontracting? That's how we.
Yeah, I think that could be fair. While we're not involved in that process, certainly the market will dictate, and the market spreads will dictate what new tariffs look like.
That's helpful. Thanks, guys.
Thanks, David.
Thank you. Our last call will come from the line of Jeanine Wai from Barclays. You may begin.
Hi. Good morning, everyone. Thanks for taking my questions.
Hey, Jeanine.
Good morning. My first question is on the maintenance CapEx, and my second question is on spacing. For the maintenance CapEx, 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 maintenance Or sorry, that midstream and infrastructure CapEx would be down about 50% as well next year. 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?
Jeanine, there's a very distinct difference between workover rigs that are used for OpEx, which is our traditional LOE, and then what we call capital workovers, which is basically converting your ESPs to their final form of lift, which is usually a rod pump. We do spend a little bit of capital, a quarter million dollars or so, per well that goes to its final form of lift, and that'll be part of the 2021 budget. It's never been a big issue for us or a big piece of our budget because we've always completed more wells than years prior and the capital budget continued to expand. Heading into 2021, if you think back three years ago, we completed about 300 wells pro forma, and those wells in 2021 are going to move to their final form of lift.
Okay, great. That's very helpful. Thank you. My second question is on spacing. In terms of the inventory and development strategy, is there any change to how you're thinking about interlateral or vertical spacing between zones in either of the basins going forward? I think I heard you mentioned earlier that spacing should probably widen at lower oil prices. We noticed kind of like a slight change in the slide. We just wanted to check in. Thank you.
Yeah, I think 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. Those spacing assumptions vary versus Howard County versus Northern Martin County versus Midland County. Continuing to refine our development program, I think secondary zones will be spaced wider than primary zones that are 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. In the Midland, we are refining spacing and while it's not widening significantly, I'd say secondary zones should get wider as oil prices go lower.
Great. Very helpful. Thank you.
Thanks, Jeanine.
Thank you. 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 not lost on me that today is Election Day, and 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 just pray for our country that we can remain calm in these 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.