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Diamondback Energy Inc (FANG -0.48%)
Q2Â 2020 Earnings Call
Aug 4, 2020, 9:00 a.m. ET
Contents:
- Prepared Remarks
- Questions and Answers
- Call Participants
Prepared Remarks:
Operator
Good day, ladies and gentlemen. And welcome to the Diamondback Energy Second Quarter 2020 Earnings Conference Call. [Operator Instructions] After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions]
As a reminder, this conference is being recorded. I would now like to introduce your host for today's conference, Adam Lawlis, Vice President, Investor Relations. Sir, you may begin.
Adam T. Lawlis -- Vice President of Investor Relations
Thank you, Laura. Good morning, and welcome to Diamondback Energy's second quarter 2020 conference call. During our call today, we will reference an updated investor presentation, which can be found on our website. Representing Diamondback today are, Travis Stice, CEO; and Case Van't Hof, CFO.
During this conference call, the participants may make certain forward-looking statements relating to the Company's financial condition, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the Company's filings with the SEC.
In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'll now turn the call over to Travis Stice.
Travis D. Stice -- Chief Executive Officer and Director
Thank you, Adam. And welcome to Diamondback's second quarter earnings call. Before we get started, I would like to take a minute to continue to extend our thoughts and prayers to all of those both directly and indirectly affected by the coronavirus pandemic. This year has brought unprecedented challenges, and I'm proud of how our organization responded, given the obstacles presented. Our teams reacted quickly to the commodity price volatility and adjusted our operating and capital plans in real time.
We are seeing the benefits of this work today with all-time low cash operating costs and capital cost per lateral foot at or below all-time lows in both basins. This is also accompanied by high graded forward development plan weighted toward the Midland Basin, where we have high mineral ownership, lower midstream and infrastructure capital requirements and higher returns due to the quality of our acreage accompanied by industry low drilling and completion costs.
Turning to the second quarter, we dramatically reduced our operated rig count in the second quarter, from 20 rigs on March 31 to six rigs today. In response to historically low commodity prices experienced in the quarter, we made the decision to complete as few wells as possible in the second quarter with zero wells turned to production in the month of June. We also curtailed 5% of our oil production during the second quarter. This curtailed production has been restored and is now receiving significantly higher realized prices than it would have received when the decision was made to curtail.
We have three completion crews working today to stem production declines and to meet our fourth quarter production target of between 170,000 and 175,000 barrels of oil per day. Importantly, Diamondback decreased activity levels throughout the second quarter while not spending excessive dollars on early termination fees or other one-time expenses that are headwinds to cash generation. Looking ahead, production is expected to continue to decline in the third quarter but rise to meet our fourth quarter guidance as we began completion operations in June with two crews and added a third completion crew in July.
We expect to run between three and four completion crews for the rest of the year and are currently running six operated drilling rigs, which is our base case for the rest of the year. In 2021, should a maintenance capital scenario become the base case, Diamondback can hold fourth quarter 2020 oil production flat, while spending 25% to 35% less than 2020's capital budget, which is also expected to include lower midstream and infrastructure budgets.
The second half of 2020 and 2021's capital programs will benefit from the drawdown of some of the DUC build from the first half of 2020 as we worked down our operated rig count as contracts rolled off. We ended the second quarter with $1.9 billion of stand-alone liquidity and have only a $191 million of our September 2021 notes outstanding after tendering for 55% of the original $400 million issuance during the second quarter. This is our only major term debt maturity before 2024.
With our reduction in forward capital spending and expectation for true free cash flow generation of current commodity prices in the second half of 2020 and 2021, we will look to reduce both gross and net debt while continuing to return capital to our shareholders through our base dividend. This dividend remains our primary return of capital to our equity holders and the Board of Directors has decided to maintain the dividend based on the current forward outlook.
To finish, Diamondback has further adjusted downward our already low cost structure and is prepared to operate successfully in a lower for longer oil price environment. A lot of the efficiency and cost gains made during this downturn will become permanent. And will benefit Diamondback shareholders in a recovery. Low interest expense, low leverage, industry leading low cash operating cost, downside hedge protection, strong midstream contracts and the benefits of Viper and Rattler will allow Diamondback to operate effectively through an uncertain forward outlook.
With these comments now complete, operator, please open the line for questions.
Questions and Answers:
Operator
Absolutely. Thank you, sir. [Operator Instructions] Sir, your first question will come from the line of Neal Dingman from Truist Securities. Your line is now live. Please go ahead.
Neal Dingman -- Truist Securities -- Analyst
Good morning. My first question, Travis for your case, I guess, we've heard a lot this year about how activity and pricing has impacted everybody's free cash flow. But again, what we've noticed for you all, and you mentioned this in the press release several times that your costs have come down notably again in 2Q. So my question is how your cost control sets you up for free cash flow generation better as it appears to me your out -- your outspend is now behind you all?
Travis D. Stice -- Chief Executive Officer and Director
Yes, certainly I'll agree that the outspend is behind us. And as I articulated the third quarter, fourth quarter and throughout next year, we'll be generating significant free cash flow. The cost structure remains one of Diamondback's significant advantages. You've heard me say before that our main focus is, is to convert resource into cash flow at the most efficient margin while we drill -- really drill and complete really good -- really good wells. The cost savings and the cost reductions that we're seeing right now through this downturn, we believe that a high percentage of those will continue throughout the forward development plan.
Historically, when we go through a cycle, you'll see service cost concessions of 10% to 15%. We're now down over 25% over the last 12 months. And as long as rig count stays below 200 rigs out here in the Permian and commodity price stays sort of range bound where it is right now, we feel pretty confident that the execution and cost metrics that we're seeing today will be part of the future, part of our future operating plan.
Neal Dingman -- Truist Securities -- Analyst
Okay. Leads me to second one, just on that plan, I was wondering on the future activity cadence and leverage, specifically you guys have now mentioned a couple of times that you can keep '21 activity flattish with -- I think you've said now with 25% less cost. So the question would be, if prices stay about at today's level into next year or even go a little bit higher, would you still potentially keep activity levels flattish and cut debt? Or how would you think about it, because, certainly, it sounds like you have the ability with these costs to come in a little bit better. So I'm just wondering if prices do rally a little bit as all others seem to be cutting production out there, what's the thought of tackling debt or looking a little bit more of activity?
Travis D. Stice -- Chief Executive Officer and Director
Yeah, certainly, we're not seeing any signals that growth is needed from Diamondback or from our industry in general. So growth in today's world is pretty much off the table. The comments I made in my prepared remarks, echoing the Board's viewpoint that we're going to -- our primary form of return to our shareholders is in the form of our dividend and our Board is committed to maintaining our dividend, and hopefully growing that into the future as well. Beyond that, excess free cash flow, as I said, we'll be using to reduce debt. So I think it's a combination of both continue to lean into the dividend and also reduce -- reduce total debt -- net debt at the same time.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, no, I think we're really focused on this Q4 exit rate number on oil of 170,000 to 175,000 barrels a day, and maintaining that that number in 2021 with the lowest capital required whether that's on the midstream side, the infrastructure side, as well as DC&E side. So we're continuing to refine that and put some guideposts around 2021. But as Travis said growth isn't top of mind today, instead, it's how capital efficient can we be to keep that production flat to 2021.
Neal Dingman -- Truist Securities -- Analyst
Great, thanks for the details, guys.
Travis D. Stice -- Chief Executive Officer and Director
Thank you, Neal.
Operator
Thank you, sir. Your next question will come from the line of Derrick Whitfield from Stifel. Sir, your line is now live. Go ahead please.
Derrick Whitfield -- Stifel -- Analyst
Thanks, good morning all.
Travis D. Stice -- Chief Executive Officer and Director
Good morning, Derrick.
Derrick Whitfield -- Stifel -- Analyst
I wanted to follow up on Neal's first question. Perhaps for yourself Travis or Danny, could you speak to the repeatability of your recent operational records with the completion of the Spanish Trail four well pad in 10.5 days and the horizontal well you drilled, and 8,000 foot in 24 hours? And if possible help us kind of quantify the savings associated with that degree of efficiency versus your average well? And Travis, we understand that every well can't be a pacesetter well, but we're just trying to get a feel for the degree of cost savings and how repeatable that could be for you guys in the future?
Travis D. Stice -- Chief Executive Officer and Director
Yeah Derrick, Danny is in the room this morning. And I'm going to let Danny answer those specifics.
Daniel N. Wesson -- Executive Vice President of Operations
Hey, Derrick. Yeah, first on the kind of repeatability point on the completion side, I mean really, that's a kind of an operational procedural change from one of our service providers and a new -- you know kind of way of attacking a zipper completion. So that's repeatable on each pad we go to that, you know that we have those simul frac crews rigged up on, it's certainly something we anticipate going forward.
And then as far as on the drilling side, the 8,000 foot in 24 hours, well that's a leading edge kind of metric and it's a basin record and a Diamondback record. I don't expect us to be beating records on every well that we drill, but certainly we'll keep edging closer to those -- those types of results. And while that's the leading leading edge markers, maybe the midpoint moves closer to that and as we continue to utilize the technology our partners are bringing us and start pushing the bounds of what we can do.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
And then I think Derrick, on the cost side, you know the dual completion crew that completes two wells at once and did that Spanish Trail pad, you're paying more for the horsepower, but you're also seeing a lot of money on the variable costs, so you're probably saving somewhere in the range of $20 or $25 a foot. And I think tangentially that benefits areas where you have high water out or high production, you're watering out your production for a lot shorter period of time, and getting that production back online. So that's a crew that we're going to use in areas where we have a lot of existing production throughout the basin.
Derrick Whitfield -- Stifel -- Analyst
Thanks. Very helpful, guys. As to my second question, I'd like to shift to the evolving regulatory environment. Perhaps for you, Travis. You've correctly outlined your minimal exposure to federal lands as a potential competitive advantage in the event that there is non-supportive industry legislation with permits and/or fracking. With the understanding that you guys are one of the more progressive E&P companies on ESG matters that are not exposed to federal lands, could you speak to your greatest regulatory concerns in the current environment?
Travis D. Stice -- Chief Executive Officer and Director
Yeah, sure, Derrick, it's a lot of -- we don't have a lot of clarity on what the -- what the regulatory environment is going to look like if we fast forward to administration change. But what we do know is that it won't speed up, things won't become more efficient. And so what we're trying to do is be as much on our front foot on things that require regulatory approval. Now you've just echoed and we have articulated that we have essentially no exposure to federal acreage, but we're going to see what the new rules of engagement are should they get rolled out, and you can expect Diamondback like you said to be progressive in the way that we navigate through those new rules of engagement.
We -- listen, we support sound science that drives regulation, and you've heard me say that before in our sustainability report and we'll continue to -- we'll continue to support regulation that's backed by sound science. When those two things deviate is where Diamondback and our industry are likely going to have a problem with the regulation.
Derrick Whitfield -- Stifel -- Analyst
Thanks, all.Well done, guys.
Travis D. Stice -- Chief Executive Officer and Director
Thank you, Derrick.
Operator
Thank you, sir. Your next question will come from the line of Scott Hanold from RBC Capital Markets. Sir, your line is now live. Go ahead, please.
Scott Hanold -- RBC Capital Markets -- Analyst
Thanks. You all in your presentation on pages I guess 10 and 11, provided your current inventory and you do have that economic sensitivity. It looks like the Midland Basin is pretty resilient in this assessment down to at least $40 to $45 a barrel. Can you give us some sense of what caused that resiliency? Is it the current well costs? And maybe if you can give a little bit of color around that inventory, where do you think that relative, I guess, I'll call it quality is versus what you've drilled to date and maybe versus what you see with compared to other peers?
Daniel N. Wesson -- Executive Vice President of Operations
Yes, Scott. I think it's misunderstood how good our Midland Basin inventory is. I kind of put our Midland Basin inventory, particularly with our cost structure up against anybody. And that's -- that's just proven based on the numbers. So you know with current well costs below $600 a foot on the Midland Basin side, we have a significant runway of quality inventory ahead of us. I think we wanted to get ahead of that that discussion topic, which seems to poke its head out once in a while. So really on the Midland Basin side, putting zero dollars of value on the gas side at $35 a barrel you have over 3,000 locations economic today. And I think that speaks to the quality of inventory and the cost structure behind that inventory.
Scott Hanold -- RBC Capital Markets -- Analyst
Yeah. And I guess my specific question would be, and you talked about well cost and you obviously have the royalty rate advantage, but can you talk maybe about the like EUR and productivity, say relative to say, some of your peers? Or is it really the cost in the royalty advantage?
Daniel N. Wesson -- Executive Vice President of Operations
That's really a combination. I mean, some of our peers, mostly the peers that are larger than us that have a significant amount of inventory, they are spacing their wells wider and doing bigger frac jobs. So they're getting a little more EUR per foot, but the costs are higher. We tended to space our wells relatively tighter at eight wells across 660 foot spacing in the Midland Basin and that's partially due to the completion design being a little bit smaller frac job, but also the cost being lower, and therefore getting a little lower EUR per foot, but from a returns perspective, you're drilling and completing those wells for multiple $100 per foot cheaper.
Scott Hanold -- RBC Capital Markets -- Analyst
Got it. Thank you. And then my follow-up question is on the conversation of maintenance spending into next year. How many wells does it take to maintain your production and to maintain that 170,000 to 175,000 on the oil side, would your your oil cuts stay flat -- I mean, what is your oil cut due to like 2021 on a maintenance plan?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, I think oil cut comes up a little bit from where it was in the second quarter because of the curtailments, but we're probably still somewhere in the low 60s. Now our maintenance plan in 2021 is moving more and more toward the Midland Basin. So that probably means a few more wells than if you were 50:50 Midland goer. But I think something similar to our gross operated well count this year with two-thirds or more focused on the Midland Basin is kind of where our heads at. And I think as we're doing our work right now to refine that analysis and refine that 25% to 35% less capital number, we'll update the market when we have that data.
Scott Hanold -- RBC Capital Markets -- Analyst
Appreciate it. Thank you.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Thanks, Scott.
Operator
Thank you, sir. Your next question will come from the line of Gail Nicholson from Stephens. Your line is now live. Go ahead, please.
Gail Nicholson -- Stephens -- Analyst
Good morning. You guys have had a nice improvement in LOE. Can you just talk about how you think LOE trends physically in the back half of 2020 and then more importantly in '21? And what drivers you have done to gain that further improvement?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, Gail, really credit to the team in the field organization who went from ramping up in April to curtailing in May and bring back that curtailed production in June to keep LOE as low as it did in the second quarter, below $4. I think that naturally that number is going to come up a little bit in Q3 and Q4, but still probably be somewhere in the lower half of the force. And then as we think about the next year, our large capital spend on the infrastructure side in terms of electrification of some fields as well as going to gas lift projects will help LOE stay in that kind of low 4s range as we head into 2021. And every cent at current production is about $1 million a year of cash flow. So we're picking up pennies and going to stay focused on being as close to that $4 bogey as we can.
Gail Nicholson -- Stephens -- Analyst
Great. And then in '21 your take or pay obligations or firm sales increased with the start-up of week to Webster. I was just kind of curious on how you guys are thinking about price realization expectations in 21% of WTI and the importance of having that exposure to brent as we move forward in time.
Daniel N. Wesson -- Executive Vice President of Operations
Yeah, I think the exposure to brent stays about the same 2020 to 2021 about 60%. But once Webster comes on that contract moves from a Midland based price to an MEH based price. I think our mentality there -- thought process is, is these type commitments and the long-term sales agreements are essentially large insurance policies for when things go bad. Right now with brent WTI as narrow as it is you were probably losing a few cents versus selling those barrels in Midland. But if brent WTI blows out $4 or $5 a barrel, then we're probably receiving somewhere close to 100% of WTI.
Gail Nicholson -- Stephens -- Analyst
Great, thank you.
Travis D. Stice -- Chief Executive Officer and Director
Thank you, Gail.
Operator
Thank you, ma'am. Your next question will come from the line of Asit Sen from Bank of America. Your line is now live. Go ahead, please.
Asit Sen -- Bank of America -- Analyst
Thanks, good morning. The DUC count of 110 to 140 at year-end '20 and you talked about drawing those, what's a good way to think about a normal DUC level in this scenario? And if you could -- I know it's a little early if I'm thinking about maintenance capital into 2022 at current strip, how should we conceptually think about Midland-Delaware split and capital needs for infrastructure?
Daniel N. Wesson -- Executive Vice President of Operations
Yes, I'll take the second part first, Asit. I think overall infrastructure is the line that we define as infrastructure will be cut almost in half going into 2021 and I think that number, we've got a large infrastructure build across our position over the last three or four years and there's a lot of scrutiny on that number to not come back up. So as we have executed on our one-time projects on electrification and gas lift, and we have very few new batteries to build instead we expand our existing batteries. That infrastructure budget is going to keep being driven down, even in 2022. You know that's a long way from today. But I think our goal is to try to be at least two-thirds Midland Basin weighted for the foreseeable future, and whether that's in a growth or a stay flat scenario, I think we have the inventory to do that.
Asit Sen -- Bank of America -- Analyst
Great. And then my follow-up question is on the ESG front. Travis, you've emphasized ESG, and on slide 20 flaring as a percent of net production has come down pretty nicely year-over-year. Could you talk about the strategies, enabling this and again remind us on the compensation metrics as it relates to ESG?
Travis D. Stice -- Chief Executive Officer and Director
Yeah. Specifically, our field organization and operations organization jumped ahead and took advantage of some of the slowdown in our drilling activity to kind of get caught up on some of the Diamondback required drilling and completion operations, particularly in the Delaware Basin. In some instances, we brought our balance sheet to bear where we spent dollars to eliminate flaring but it's essentially across the board, a heightened emphasis to not flare at all. And we do need the times help from our gathering partners to make sure that once we are hooked up that they can move the gas. But, but in general, we've adopted a policy of every well is connected to a -- to gas sales point before it's brought on. And that's -- that plus working closely with our gathering and processing partners has allowed us to really substantially reduce our flaring.
Daniel N. Wesson -- Executive Vice President of Operations
Yeah. And Asit, I mean we've even taken the matter in our own hands by converting some of these contracts that we -- the legacy contracts that we have from POP, percent of proceeds over 100% fixed fee, and that's what's driving our gathering and transportation costs going up by a little bit this quarter. Now we catch the benefit of that on the realized price side on the gas front. So it's really a neutral trade and the higher the gas goes up the more we're exposed to that on the Diamondback side. So using the legal and the contract route to incentivize our gatherers and processors on a fixed fee basis to take our gas.
Travis D. Stice -- Chief Executive Officer and Director
And we've got on the -- in fact you can read it, I said, on Slide 21, some of the changes we made to our short-term incentive compensation program and as a reminder, this scorecard -- this corporate scorecard that we presented our proxy that makes up half of every employees' short-term incentive compensation on an annual basis. So we've got a 15% weighting on our ES&G measures and you can see what you can see what those are on Slide 21 with their safety metrics, flaring, greenhouse gas emissions, the percent of recycled water, oil spill control and TRIR or total recordable incident rate. So there's five measures that make up that ES&G score now.
Asit Sen -- Bank of America -- Analyst
Appreciate the color. Thank you.
Operator
Thank you, sir. Your next question will come from the line of Jeff Grampp from Northland Capital. Your line is now live. Go ahead, please.
Jeff Grampp -- Northland Capital -- Analyst
Good morning, guys. You guys have communicated pretty clearly an aspiration to reduce debt here on an absolute relative basis over the next few quarters. So I was wondering if you guys have kind of targeted either an absolute or relative level on the debt side that you guys would want to get to before assessing and increasing returns to shareholders?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Jeff, I don't think they're mutually exclusive. We've raised our dividend every year since putting it in place three years ago. And I think that being the primary return of capital, we're going to look at that very closely at the end of the year and see what 2021 holds on that front. The one consistent theme we received from our largest shareholders over the past -- over the past few months is to protect the dividend and in exchange for protecting our dividend cut capital, and that's what I think we're going to do.
I think overall, we would like our debt to be lower than higher and I don't want to put out a two-year or a five-year target on that front because a lot can change in this business as you've seen in the last -- in the last three months. But I do want to also emphasize that as the parent company, we still have three companies, right. And each of those three companies has debt that's manageable, all three companies will be generating free cash flow starting in the third quarter going forward. And on top of that, Diamondback has a lot of ownership in those two subsidiaries, which while you won't -- you can't sell all that in a day, at some point that is a safety valve for how much debt you think you have at the parent company.
Jeff Grampp -- Northland Capital -- Analyst
Got it. [indecipherable] my follow-up, Travis wanted to pick your brain on the M&A front, maybe from a couple of angles. First is just generally your comfort level of taking a serious look at any deals in this environment? And second is just any level of interest in terms of diversifying the asset base outside of the Permian? Do you see benefits to that from Diamondback's perspective or do you think it's more of a competitive advantage to have the concentration and the knowledge base that you have in the Permian?
Travis D. Stice -- Chief Executive Officer and Director
You know, look, in terms of the first part of your question, M&A. We are so internally focused right now on the -- on doing the things that we need to do. Look our industry has been rightly criticized for all kinds of noise that have distracted from returns and our focus right now is singularly trying to deliver the highest returns and cash flow for every single dollar we invest. And look, from the public guys, the debt is trading so poorly for the public guys that could potentially be targets. It just doesn't make any sense for us right now. So that's kind of my view on -- that's my view on M&A.
And then I just don't think -- I just don't think that it makes sense for Diamondback to be looking at other basins. We are -- one of the core philosophies we talk about here is know what you're good at. Diamondback is really, really good at Permian Basin extraction of hydrocarbons and that's borne out by our cost structure and our execution metrics. And that's our emphasis, that's what we're good at, that's what we know we're good at and that's what we're going to maintain.
Jeff Grampp -- Northland Capital -- Analyst
All right, I appreciate it, Travis. Thanks for the time guys.
Operator
Thank you, sir. Your next question will come from the line of Arun Jayaram from JP Morgan. Your line is now live. Go ahead, please.
Arun Jayaram -- JP Morgan -- Analyst
Yeah, good morning. Travis, your guidance implies call it a 60:40 split in footage between the Midland-Delaware basins this year. I was wondering if you could give us maybe some more thoughts on how that mix could look as we head into the back half of the year? And perhaps any preliminary thoughts on '21?
Travis D. Stice -- Chief Executive Officer and Director
Sure. I'm going to let Kaes answer that. He's got his spreadsheet in front of him.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, Arun. The 60:40 really is driven by a lot of the first half of the year being in the Delaware Basin and looking into the back half of the year Q3, Q4 and into 2021, we've really moved the rig schedule and the frac schedule to about 70:30 Midland-Delaware. And well, I don't have my spreadsheet in front of me. That's kind of the path forward is what's, let's get more focused on the Midland Basin, where we have less infrastructure needs, less midstream needs, lower LOE and probably better returns and an overall cost structure. So I think for us six rigs operating, four of them are in the Midland and two in the Delaware.
Arun Jayaram -- JP Morgan -- Analyst
Yeah. And Kaes if you're going to characterize what the spread and call it an oil breakeven is today kind of using some of your leading edge well cost, what would you say the spread is?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
I think it's less than $5, but somewhere around $5 a barrel, your breakeven in the Midland, a little bit lower than the Delaware. I mean, I just think if you're running $5, $5.75 or $5.80 as your cost per lateral foot, that's a pretty good return in projects with some of these Midland Basin wells in the 80, 90, 100 barrels a foot EUR range.
Arun Jayaram -- JP Morgan -- Analyst
Okay, that's helpful. Just my follow up, quite a few incoming questions just on next year's capex thoughts, obviously you released this couple of two or three weeks ago but just the 25% to 35% decline year-over-year to keep 4Q oil flat. You did highlight some lower infrastructure costs. But what type of well cost is kind of embedded within that range? Are you using basically the 2020 updated outlook for well cost, but maybe just a little bit of color on that would be helpful?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, I don't think we would use the 2020 updated outlook, the real-time cost to drive that number. We're really kind of using the lower end of our full-year 2020 guidance range. We -- I think Travis mentioned earlier in the call, well costs are down 25% year-over-year, probably 50% of that service costs related, but I think for us to guide to all-time low well costs in 2021 would not be a prudent idea.
Arun Jayaram -- JP Morgan -- Analyst
Got it, got it. Thanks a lot, Kaes.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Thanks, Arun.
Operator
Thank you, sir. Your next question will come from the line of Jeanine Wai from Barclays. Your line is now live. Go ahead, please.
Jeanine Wai -- Barclays -- Analyst
Hi, good morning everyone and thanks for taking my questions. My first question is, following up on some of the higher ones on productivity and activity allocation. Can you tell us how you anticipate the corporatewide productivity per foot to trend in 2021 relative to 2020? And I guess we're asking because I know that there's been some change recently and there is some preference between high grading zones that are more modest, price environment versus more co-development versus kind of lease retention?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Well, I think, Jeanine, overall with more Midland Basin as a higher percentage of your total capital, your Midland Basin EUR per foot is lower than the Delaware, but your well costs are significantly lower. So well I can't give you an exact productivity on well EUR per foot. I do think in general the -- with a couple of hundred wells, we're going to complete in 2021, will be a higher productivity on returns basis than 2020 because in 2020, we were heading into the year to complete 350 wells and we have slowed that machine down to complete 185 this year and something close to that next year. And I think just in general, our next 80, 85 wells, I see on the schedule for the second half of 2020 are significantly better than the first half of 2020 and then we expect that level of detail on drilling our best stuff first to carry into 2021.
Jeanine Wai -- Barclays -- Analyst
Okay, great. Thank you. That's really helpful. My second question is just back on capex. I know you released the updated production and capex guide. Last night, you provided helpful breakout between the different components, which were kind of resets in the higher end and not to rehash old news or anything like that, but I still think that there is a lot of questions on some of the moving pieces on that 2020 update, especially on the D&C side, given that you're completing the same amount of net wells as you previously planned and exiting with some less DUCs. So maybe just a little bit of color there for some clarification would be helpful. Thank you.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Sure, Jeannine. I think I think what's unique about how Diamondback reports capex is that it's a number that actually matches the cash flow statement and sometimes that that's been to our detriment particularly in the first half of the year. So in general, we came into the year running 23 rigs and eight completion crews, and we're going to exit the year running five or six rigs and three or four completion crews and that results in a net cash outflow and our cash drag of $250 million or $300 million on the budget. And I think for others who report accrued capex, it doesn't match their cash flow statement. We on an activity based basis are going to do kind of 1.55% to 1.60% [Phonetic] of capital this year with a large cash outflow drag heading into next year.
Jeanine Wai -- Barclays -- Analyst
Okay, great, thank you very much.
Travis D. Stice -- Chief Executive Officer and Director
Thanks, Jeanine.
Operator
Thank you. Your next question will come from the line of Leo Mariani from KeyBanc. Your line is now live. Go ahead, please.
Leo Mariani -- KeyBanc -- Analyst
Hey, guys. Wanted to follow up a little bit on the cost side, certainly looking at your leading edge well costs that you guys are talking about in your slide deck in both the Midland and Delaware. Certainly those appear to be below your 2020 guidance in terms of cost per foot. Just trying to get a sense there. Do you think kind of the full-year '20 Midland and Delaware, DC&E well cost per foot guide might end up being a little bit conservative? Or are you just kind of maybe being a little reluctant to kind of just change things sort of near here?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, I think we're a little reluctant to changes, just because there's -- half of the year is gone in the way we report capex probably three quarters of the year has essentially gone on well cost perspective. But these lower well cost that we're seeing today in real time will benefit the Company in the fourth quarter and into 2021. So I think, I don't think it's prudent for us not to change that guidance but certainly we expect the trend to continue.
Leo Mariani -- KeyBanc -- Analyst
Okay, that's helpful. And I guess, clearly you guys are very focused, it seems to be on maintenance mode in a $40 oil world and rightfully so, Travis you certainly talked about not having kind of the right signals in this current environment to really indicate for anyone in the industry to pursue production growth. I guess what do you think the right signals might be for the kind of FANG and the US industry in general to come maybe you start thinking about returning to production growth.
Travis D. Stice -- Chief Executive Officer and Director
Well certainly you got to have a -- you've got to have a lot -- a lot higher commodity price. I don't know what higher means, but certainly materially higher than what you see today. You also have to have -- you also have to have access to capital, which right now has been, there has been a capital starvation for a number of quarters for our industry and rightfully so as I mentioned earlier, because of our industries and ability to generate extra returns. But it's -- and then the last part of that would be that -- certainly investor sentiment would have to change dramatically from where it sits today.
So there is quite a bit of, quite a bit of headwinds I think for our industry as you look ahead to try to think about any kind of meaningful production growth.
Leo Mariani -- KeyBanc -- Analyst
Okay, thanks guys.
Operator
Thank you, sir. Your next question will come from the line of Charles Meade from Johnson Rice. Your line is now live. Go ahead please.
Charles Meade -- Johnson Rice & Company -- Analyst
Good morning, Travis, Kaes, and the whole team there. I wanted to ask in terms of -- and this goes back to a comment you made earlier in response to one of your earlier questions about the rig count staying under 200 in service costs. If you go back to the end of last week, couple of the bigger operators out there, two majors, I think everyone expected them to be dropping rigs, but they really indicated that they're going to be dropping quickly or dropping a lot of rigs into year-end. And I'm curious as you look forward in the back half of '20 and into '21, as that rig count continues to go down. How do you see things changing for you as an operator or maybe just in your environment or the greater ecosystem out there?
Travis D. Stice -- Chief Executive Officer and Director
Well, certainly, if we continue to have this environment, as I mentioned earlier, well costs are really going to stay the same, but they're going to go lower. And I think it's reasonable that if commodity prices increase, you'll start to see the service sector, the service sector -- the service sector respond. But look, this -- the Permian Basin is going through a seismic shift in a capital allocation from all the operators and you can see it in the production responses. We're now below 4 million barrels of oil a day of production. And so I just, it's just hard to see in this environment any meaningful change in the current -- in the current operating situation that that all the companies are faced with here in the Permian.
Charles Meade -- Johnson Rice & Company -- Analyst
Got it. That's it from me. Thank you.
Travis D. Stice -- Chief Executive Officer and Director
Yeah, and Charles, just to add to that though is, with this continued reduction in activity and even in this environment, I can't emphasize enough that that Diamondback's clear advantage is not only the number of -- the number of locations we have that we laid out in our slides in terms of inventory, but it's our cost structure and so the lower and lower the price of the commodity goes, the more the margins get squeezed, the more really efficient high margin companies get highlighted. And certainly Diamondback as evidenced by our numbers in this release falls into that category.
Charles Meade -- Johnson Rice & Company -- Analyst
Thank you, Travis.
Operator
Thank you. And your next question will come from the line of Brian Singer from Goldman Sachs. Your line is now live. Go ahead, please.
Brian Singer -- Goldman Sachs -- Analyst
Thank you. Good morning to you all. Can you talk to how this year and the run up to this year have changed your views, if at all longer term, on the oil price, on the right amount of production to hedge? And then if we are in a lower Diamondback plus industry growth environment in the Permian, the strategic value of your interests in VNOM and Rattler?
Travis D. Stice -- Chief Executive Officer and Director
Brian, the -- Kaes mentioned earlier about how Diamondback has a large ownership position in both our subs and that continues to literally and figuratively pay dividends to Diamondback shareholders and it's something -- something that Diamondback Board is aware of, but it's, we're comfortable in our position and in our ownership of those subs today. Do you want to add anything to that, Kaes?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
No, I think on the hedging side, most -- most of our hedge is restructured as two-way callers and so we have a slide in our deck where we are exposed to the upside here and we have a good amount of 2021 production hedged. We haven't added -- added much on that front. We've actually restructured and lowered the total exposure in 2021. But overall, I think if we're moving toward true free cash flow model that distributes a lot of cash to shareholders, Diamondback should emulate what Viper and Rattler have done over the past couple of years, which is distribute a lot of cash back to -- back to their shareholders, one being Diamondback.
But more hedging, I think is probably in our future and making sure your dividend is protected on the bottom end and you print a bunch of free cash on the top end of those two way callers.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you. And then my follow-up is, what are you seeing from outside operators in the Permian? And if oil prices do rise, do you have a sense, if the level of discipline from the outside operators will be lower or greater than your own?
Travis D. Stice -- Chief Executive Officer and Director
Well, certainly our industry doesn't have a good track record of that discipline. But I believe that there has been a -- there has been a change in sea level in terms of discipline and I'm confident that all operators that at least had any awareness of our industry are going to be very judicious in trying to resume activities that generate production growth.
Brian Singer -- Goldman Sachs -- Analyst
Great, thank you.
Operator
Thank you, sir. Your next question will come from the line of Michael Hall from Heikkinen Energy. Your line is now live. Go ahead, please.
Michael Hall -- Heikkinen Energy -- Analyst
Thanks guys, I appreciate the time. I just wanted to do, I guess, follow-up on one thing and then also ask, I guess on base declines. Maybe first on the declines, I'm just curious as you guys have slowed down a bit here this year, what -- how would you think about the impact of that on the base decline profile as you look at '21, exiting '20 entering '21 relative to how things look exiting '19 heading into '20? What's the change in base decline rate there?
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, Michael, on the oil side, we released high 30s was our base decline exiting 2019 going into 2020 and I think that probably goes somewhere in to the mid 30s. I can't guarantee the low 30s yet, but probably the mid 30s on at least on oil, so probably 300 bps or 400 bps of benefit. On the BoE side, we were at low 30s kind of 32%, 33% this year, 2019 going into 2020 and that probably goes down a couple of 100 bps lower into the near the 30% range.
Michael Hall -- Heikkinen Energy -- Analyst
Okay, that's helpful. And then I guess the follow-up is on the M&A commentary, it seems like maybe Travis you're referring to the public space in that commentary. I just wanted to follow up, is your view that M&A doesn't really make sense is that applicable in both public and the private space? Or is it worth differentiating between the two at this point?
Travis D. Stice -- Chief Executive Officer and Director
Well it's all about the rock, right. So, I mean if you find good rock, you shouldn't care whether it's public or private. But the problem that we're seeing on the public side is we have all of the debts trading for public companies and that has a significant detriment on acreage valuation. On the private side, there's just not that many opportunities out there truthfully of Tier 1 acreage. I mean, we're not going to -- there is no, there is no, there's just not a lot of Tier 1 rock that's out there and that's kind of how we're differentiated.
Michael Hall -- Heikkinen Energy -- Analyst
Okay, that's helpful. I appreciate it guys. Thanks so much.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Thanks, Michael.
Travis D. Stice -- Chief Executive Officer and Director
Thanks, Michael.
Operator
Thank you, sir. Your next question will come from the line of Richard Tullis from Capital One Securities. Your line is now live, sir. Go ahead, please.
Richard Tullis -- Capital One Securities -- Analyst
Thank you, good morning. Kaes, it was mentioned a couple of times that the dividend is the primary vehicle for returning cash to shareholders. I just wanted to get your thoughts on potentially Diamondback implementing say a variable dividend that paid out a certain percentage of excess cash flow yearly.
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Yeah, I mean, Richard, my opinion is, I've heard a lot of talk about the variable dividend and the only variable dividend I've ever seen is at Viper in our space. But for us, the fixed dividend is the priority. And I think in the conversations with our largest shareholders, they want to be running kind of a dividend growth model as how they're getting cash back from their investment in Diamondback and I think overall it's a good concept, but it's just not a concept that we're focused on right now. We're focused on the base dividend which our peer group has the highest yield today and I think investors knowing that safe is important and knowing that that's going to grow in the future is also important.
Richard Tullis -- Capital One Securities -- Analyst
Sure. And then just as a follow-up. Looking at the base case 2021 budget of around six rigs maybe, for Travis or Danny, do you envision allocation of some level of capital in that scenario to continue testing your acreage such as going back to limelight area or other intervals?
Daniel N. Wesson -- Executive Vice President of Operations
There might be a little bit in there, Richard. But it's going to be as muted as possible, I mean I think I think given the shocks that the industry has gone through over the last four months just exemplifies our precious capital is and I think a lot of our land owners have been pretty, pretty accommodating through this and we're going to do what we can to hold acreage, but also only drill our best stuff with the majority of the capital.
Travis D. Stice -- Chief Executive Officer and Director
Yeah, Richard. We remain singularly focused on delivering the highest returns and cash flow per share for each dollar that's invested and every capital allocation decision that we make runs through that aperture and we will be consistent with that on a go-forward basis.
Richard Tullis -- Capital One Securities -- Analyst
All right. Well, I appreciate it. Thank you.
Travis D. Stice -- Chief Executive Officer and Director
Thank you, Richard.
Operator
Thank you, sir. I am showing no further questions at this time. I would now like to turn the conference back to CEO, Mr. Travis Stice.
Travis D. Stice -- Chief Executive Officer and Director
Thank you, again to everyone for participating in today's call. If you've got any questions, please contact us using the contact information provided. Stay well.
Operator
[Operator Closing Remarks]
Duration: 50 minutes
Call participants:
Adam T. Lawlis -- Vice President of Investor Relations
Travis D. Stice -- Chief Executive Officer and Director
Kaes Van't Hof -- Chief Financial Officer And Executive Vice President of Business Development
Daniel N. Wesson -- Executive Vice President of Operations
Neal Dingman -- Truist Securities -- Analyst
Derrick Whitfield -- Stifel -- Analyst
Scott Hanold -- RBC Capital Markets -- Analyst
Gail Nicholson -- Stephens -- Analyst
Asit Sen -- Bank of America -- Analyst
Jeff Grampp -- Northland Capital -- Analyst
Arun Jayaram -- JP Morgan -- Analyst
Jeanine Wai -- Barclays -- Analyst
Leo Mariani -- KeyBanc -- Analyst
Charles Meade -- Johnson Rice & Company -- Analyst
Brian Singer -- Goldman Sachs -- Analyst
Michael Hall -- Heikkinen Energy -- Analyst
Richard Tullis -- Capital One Securities -- Analyst
