Diamondback Energy Inc (FANG) 2020 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Diamondback Energy Fourth Quarter 2020 Earnings Call. (Operator Instructions) Please be advised that today's conference is being recorded. (Operator Instructions)

I would now like to hand the conference over to your host, Vice President of Investor Relations, Adam Lawlis. Sir, please go ahead.

Thank you, Latif. Good morning, and welcome to Diamondback Energy's Fourth 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 conditions, results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC.

In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.

I'll now turn the call over to Travis Stice.

Thank you, Adam, and welcome to Diamondback's fourth quarter earnings call. Diamondback continued to execute well in the fourth quarter of 2020, setting the company up for continued solid operational performance in 2021. The benefits of the company's strategy to move activity to our most productive areas in the second quarter of 2020 is now starting to pay dividends in terms of capital efficiency and early-time well performance.

Well costs and cash operating costs remain near all-time lows, and our average completed lateral length in the fourth quarter was over 13,000 lateral feet, a company record. These operational achievements will translate directly into increased returns to our stockholders as commodity prices have risen in recent months.

We are still operating in a market supported by supply that's being purposefully withheld to allow global inventories to decline as demand recovers from the depths of the global pandemic. Diamondback continues to see no need to grow oil production into this artificially undersupplied market and instead plans to hold fourth quarter 2020 production flat while generating free cash flow used to pay our dividend and pay down debt.

The Board's decision to increase our dividend by 7% exhibits its confidence in the forward development plan released today, further demonstrating our commitment to capital discipline. Our capital allocation philosophy remains unchanged: Hold production flat in the most capital-efficient manner, with free cash flow used for our dividend and to pay down debt. Growing our dividend and paying down debt are not mutually exclusive, and the majority of our free cash flow will be used for debt paydown in 2021.

The fourth quarter of 2020 built on the momentum started in the third quarter, with free cash flow increasing to over $242 million, up 58% from the $153 million of free cash flow generated in the third quarter last year. We expect this trend to continue in 2021, where we currently expect to generate nearly $1 billion of free cash flow at $50 oil pro forma for the closing of our acquisition of Guidon this Friday.

This free cash flow implies a reinvestment ratio below 60% at $50 oil in the midpoint of our $1.35 billion to $1.55 billion capital budget for this year. Note that our CapEx guidance includes the addition of approximately $100 million of capital for the Guidon acquisition, which encompasses one net operated rig added as well as associated infrastructure and environmental spend.

Our production guidance that ties to this capital budget for 2021 assumes that we hold Diamondback's expected fourth quarter oil production of 170,000 to 175,000 barrels of oil per day flat, plus 10 months of the 12,000 barrels of oil per day that Guidon was producing at time of acquisition announcement.

This production guidance also accounts for the estimated impact of the severe winter storms in the Permian Basin last week, which we estimate to have knocked out the equivalent of 100% of our production for 4 to 5 days. Production has nearly returned to pre-storm levels as of today, and we expect to make up a majority of the lost production throughout the year, but will not be able to make it all up in the first quarter.

The stockholder meeting to vote on our pending merger with QEP Resources is scheduled for March 16. The merger is expected to close shortly thereafter, subject to QEP stockholder approval. Should the deal approve, we will update the market on our pro forma plans as soon as practicable after closing. While this creates a noisy first quarter in terms of production additions, it will also create a clean look at the pro forma business in the second quarter and beyond.

We have only one material term debt maturity due in the next 4 years, $191 million that remains outstanding on our 2021 maturity. We expect to have cash on hand to retire this note when it is callable at par later this year. After this maturity, we do not have any material outstanding obligations until 2024. We also have a legacy high-yield bond due 2025 that's currently callable, providing optionality for further gross debt reduction as free cash flow materializes.

Turning to ESG. Diamondback today announced a major initiative relating to ESG performance and disclosure, including scope 1 and methane emissions intensity reduction targets, as well as a commitment to point forward Scope 1 carbon neutrality or Net Zero Now. We are committing to reduce our Scope 1 GHG intensity by at least 50% from 2019 levels by 2024, and we are committing to reduce our methane intensity by at least 70% from 2019 levels, also by 2024. A detailed breakdown of our Scope 1 and methane emissions from 2019 can be seen on Pages 13 and 14 of our latest investor presentation.

Diamondback expects to continue to reduce flaring, which is now down almost 90% from 2019 levels, directly impacting over 50% of our 2019 Scope 1 emissions. We also expect to spend approximately $15 million a year over the next 4 years to retrofit about 600 of our tank batteries with air-powered pneumatic control systems, replacing methane-emitting, gas-operated pneumatic control systems. These 2 changes will be significant drivers in reducing our carbon footprint, but other initiatives like methane leak detection and full-field electrification will also have a direct impact on our emissions reduction strategy.

Diamondback today also announced the Net Zero Now initiative, which means as of January 1, 2021, every hydrocarbon molecule produced by Diamondback is anticipated to be produced with zero net Scope 1 emissions. The GHG and methane intensity reduction targets mentioned earlier are the primary focus as it relates to our environmental responsibility.

But we recognize we will still have a carbon footprint. Therefore, carbon offset credits will be purchased to offset our remaining emissions. Eventually, we expect Diamondback or one of our subsidiaries to invest in income-generating projects that will more directly offset our remaining Scope 1 emissions, but the credits are a bridge to that time and place.

With these major announcements, Diamondback has chosen to adopt a strategy to operate with the highest level of environmental responsibility. Our social and environmental license to operate as a public oil and gas company based in the United States is going to be influenced by our capital providers, and we do not expect our investor pressure for oil and gas companies to improve their environmental performance to subside anytime soon.

It is incumbent on us to improve our environmental performance and compete for capital in an industry with ever-increasing external pressures. Carbon emissions are a cost, and Diamondback is working to become the low-carbon operator in addition to our leadership position as the operator with the lowest capital and operating cost.

I'm very excited about Diamondback's current position and the strength of our forward outlook as evidenced by our 7% dividend increase announced yesterday. We are forecasting significant, consistent free cash flow generation translating into returns to shareholders. We look forward to successfully closing and integrating the Guidon acquisition and the QEP merger, and we'll update the market on our pro forma plans as soon as practicable.

With these comments now complete, operator, please open the line for questions.

(Operator Instructions) Our first question comes from the line of Arun Jayaram of JPMorgan.

Travis, I wanted to pick your brain a little a bit about the long-term kind of profile at Diamondback. On a pro forma basis, in our model, which includes QEP, we calculate about $1.4 billion of after-dividend free cash flow over the next 5 years. And I think your dividend is about $300 million, so call it $1.4 million after the dividend or $7 billion.

You guys talked about today paying off a little less than $200 million of debt due later this year, plus funding the $375 million of cash from the Guidon acquisition. And then also it sounds like leaning into the dividend on a go-forward basis is something you plan on. But I guess our broader question is what are your plans on a longer-term basis in terms of deploying this excess cash?

Well, certainly, Arun, that's a good problem to have, right? And I think our cost structure really magnifies our ability to generate that free cash flow. First, the operating metrics of the company continue to just look outstanding. So I'm really excited about that, and we've evidenced it now for a couple of quarters.

But at the Board level, we consistently talk about leaning into the base dividend and continuing to enhance our shareholder -- as a form -- as a way of enhancing our shareholder return program. And it's really, like I said, a problem of blessings to have that kind of free cash flow.

We want to continue to work the debt quantum down, which we intend to do so. And we'll do like we've always done and be creative in returning that money back to our shareholders. I've been very demonstrative in our stance of not trying to grow production. So any fears that we're going to take money and start drilling more wells with it this year is just off the table. So it's a good problem to have.

Yes. Arun, on the debt side, I think, in general, anything that has a maturity prior to 2029 is on the table for debt paydown. And I think we're looking to set the business up to have kind of a turn of permanent leverage with a long-term maturity over 10 years at $50 oil. So in the front end of the curve, all that debt is eligible for paydown, but also not mutually exclusive from the base dividend continuing to increase here.

Got it. Got it. Kaes, maybe my follow-up is for you. One of the questions we got last night was just looking at the Midland Basin, D,C&E got on a lateral foot basis, I think you averaged about $520 a foot in the second half. The 2021 guide is a little bit above that. So I just wanted to understand what you're dialing in, in terms of perhaps some inflation. And does the -- is there a mix effect with the Guidon assets being added there? I assume that this is excluding QEP.

Yes. There's nothing on the mix side, Arun. I think we've said in the past, we're not going to guide to all-time low well costs. I think right now, we're in the $500 to $520 a foot range and we're trying to hold on to that as long as we can. We know that the service industry has suffered through this downturn as much as anybody, if not more. And there are some pricing pressures at the margin. I wouldn't say it's on the big-ticket items, but you are starting to see some pressure on casing prices and smaller field service items.

So like we talked about, the midpoint of our guide is 8% to 10% above where well costs are today. I would hope the good guys can keep some of that on our side and outperform as we go through the year. But just being conservative. Today is February 23 and we've got 10 more months left of, hopefully, $55-plus oil, and that will result in some service cost pressures.

Our next question comes from the line of Neal Dingmann of Truist Securities.

Kaes and Travis, my question is, I know -- I'm trying to think how long, it hasn't been too terribly long ago you all restructured, I know, your gathering and processing. You took, I think, at your expense on that. Could you talk a bit about now the benefits of that from a -- just not only from a pricing but from -- I know some folks earlier around the storm and all were having trouble, how people take their gas. Could you just talk about both those aspects? And now sort of after converting those contracts from a percent of proceeds to a fixed fee, kind of what -- if there's anything more that's needed to be done and the benefits there.

Yes. Neal, I mean, we had a pretty high flaring number in 2019, and it was pretty frustrating to us that, that number was as high as it was. Unfortunately, it was that high because we had a gas processor who had a percent of proceeds contract that was losing money on that contract, and therefore, it wasn't very fair on how much they sent us to flare versus some of their other contracts. So we took that price risk and decided to restructure that contract into a fixed fee deal. And you can see in the flaring numbers, our numbers have come down dramatically, mostly because of that particular contract moving to fixed fee.

Now with NGLs and gas rally, that fixed fee stays the same and we get the benefit as the operator. So that's helping a lot. I don't think it had a lot of impact on -- from a storm perspective. I think our field organization during the storm actually stepped up to get power -- or get natural gas flowing back to local power plants in the Permian, which eased the problem and stopped the rolling blackouts in the Permian almost immediately. So 2 separate items, but certainly proud of the field organization for what they did for the cities of Midland and Odessa.

Yes. Nice changes there. And then Travis, just my follow-up. Just on the efficiencies you've seen, could you talk -- maybe give us an idea, I think, let's call it, post-QEP. I know you've talked about maybe going to 8, 9 rigs. I'm just trying to get an idea of both on the D&C side, how many -- like kind of what you're up to now as wells per year? For a while, what was it, 6 to 7 rigs and you were talking about completing, I don't know, nearly 200 or up to 200? Could you give us idea of kind of where your optimal efficiencies are? And is there -- I mean, it really is just at sort of what I call crazy levels versus where we were a couple of years ago. I'm just wondering can that get any better.

Yes. I think, Neal, the rigs, the efficiencies continue to creep up. But we're going to run, I think, 9 rigs essentially average for the year to drill 190 wells, 75% of that in the Midland Basin, all over 10,000 feet. But really, the efficiency that's improved is on the frac side. I mean I think our completion cadence, we're expecting to complete 220 to 225 wells all over 10,000 feet, with 3 simul frac crews and 1 spot crew.

So really, the efficiency on both sides is pretty dramatic. And you can see that also in the lateral length, right? I mean we completed over 13,000 average lateral feet in Q4, and we're looking for opportunities throughout our entire asset base to push lateral length to that 12,500 or 15,000 foot range.

Yes. Neal, I'll just add to that, that this time last year, just prior to this time, we were running over 20 drilling rigs. And today, we're running 7 or 8. And when you go from that many rigs to that few of rigs, you have the opportunity to high-grade your rigs. And then secondarily, when activity really troughed in the second quarter of last year, rather than just sitting on our hands and bemoaning the outlook, our organization really leaned in to try to improve efficiencies. It was a great opportunity with less field activity going on to really examine all of the processes, both on the drilling and completion side and on the production side as well.

And so we took advantage of that trough in activity. And as the industry picked back up and as our activity picked back up, we were able to kind of make permanent some of those efficiencies that we revealed through the second quarter and early third quarter. So really proud of that, and I think we're going to see the direct benefits of that in 2021, and that's going to translate to more cash flow for our shareholders.

Our next question comes from the line of Gail Nicholson of Stephens.

The Net Zero Now strategy is great. Can you talk about the expectations on the cost of purchasing carbon offsets? And is that something that will be done at year-end? And is that cost in the infrastructure and environmental CapEx line item?

Gail, I'll start with the added CapEx. The big piece and the big goals here on the GHG side are the emissions reductions, right? I think the Net Zero Now initiative is a great addition to the story, but it's not the primary focus. And the primary focus happens to be working down all the numbers you see on Slide 13 and 14. And so the big dollars we're going to spend, we're going to spend about $15 million a year converting legacy air -- or legacy gas pneumatic tank batteries to air. And those batteries run off methane essentially, and converting that to air dramatically reduces your methane intensity automatically.

So I'd expect to see $15 million a year in the budget for that, and we've also built that in on the Guidon and QEP acreage as we get a hold of that and look to convert that. The carbon credits, we've already -- are in process on a contract for some carbon credits. I won't give all the details, but I'll say it's a mid-7-figure number, not an 8-figure number. And the projects that we're investing in are tied directly to carbon capture or carbon sequestration rather than the tree planting side of the business.

Gail, we're not trying to buy our way into carbon neutrality. As I mentioned in my prepared remarks, the purchasing of these carbon credits are really just a bridge until we get our operations enhanced and maybe look at some other future investments down the road. But we're really trying to invest in the future. And you know how tight Diamondback runs our CapEx. And spending money on tax credits actually provides us a great incentive to not use those by doing the right things out in the field, like Kaes was mentioning and articulating, to effectuate these changes. And it's a nice bridge in the interim, but that's not the focus of what this initiative is about.

Great. And then there's been some discussion lately regarding the benefits of hedges. Can you talk about the hedging strategy on a go-forward basis? And Kaes, specifically, in your view, how important is hedging to be able to deliver a consistent free cash generation profile?

Yes. I think it's really important, Gail. And I think in the depths of April and May of last year, I told Travis that do not get mad at me if we lost money on some hedges in 2021. And now we're at that point and the commodities rallied, and I think we're sleeping a lot better at night knowing that the commodities rallied. So I think, overall, if you look at our hedge book, we've tried to keep very wide 2-way collars. We're at the bottom end of our collars. We're protecting our dividend and protecting -- paying down some near-term maturities, but also trying not to limit all the upside to our shareholders.

So I think you'll see us keep building that hedge book with wide collars. I think the percent hedge that we have is inverted just like the forward curve, and I think we're going to be patient adding hedges. But overall, I still think hedging is an important philosophy for an oil and gas company to guarantee returns and guarantee returns to shareholders in the form of true cash distributions.

Gail, I just want to return to your question that you asked earlier and reemphasize the point that we feel like we have a social and environmental license to operate. And I'll tell you, for the last multiple quarters, we've been really digging into this. But one of the things that surprised me was relatively, it's still a lot of money, but relatively how little cost is required to do the right thing here with regards particularly to methane emission and converting these tank batteries.

And I think as other companies kind of dig into that, I hope they find the same outcome that it is real dollars and it is real shareholder funds that we're diverting away from the drill bit, but it's not as bad as maybe what we were originally thinking. And again, I'd just go back to our environmental and social license and trying to do the right thing here.

No, I agree. It's basically a 2- to 3-well diversion every year to get this pneumatic gas on your batteries installed, which makes a huge difference. So I congratulate you guys are making that effort and more companies should do that.

Thank you, Gail. And yes, it does sting a little bit, but I think it's the right thing to do.

Our next question comes from the line of David Deckelbaum of Cowen.

Just wanted to ask around lateral lengths. As you integrate Guidon and, hopefully, QEP here, you saw a tick up on this larger pad in the fourth quarter where you were averaging 13,000 feet per well. You budgeted next year at 10,000, I guess, for FANG and Guidon. Should we expect that number to tick up in '21 and '22? I would imagine as you're integrating 2 assets, the availability of swaps kind of opens itself up there. Can you talk about where that lateral length progression is moving? And is this something that we should be thinking about the over for -- on that 10,000 per well over the next couple of years?

Yes. David, good question. I mean I think the beauty of the Guidon and QEP assets as they sit relative to our position is that you have -- they all fit hand in glove. And so that gives us an opportunity to push lateral lengths for one of our -- what will be our biggest operating area for the next few years.

So I'd put 10,000 as the floor. We still have rigs running outside of that main block. But if we're having -- and we're going to have half of our rigs running in the big block in Martin County, I'd expect those 5 rigs probably average a little higher than 10,000, whereas the rest of the position might be a little below it. So could we get it up to -- up 10%? I think that's possible. But again, the teams are doing their work. And the contiguous nature of that block is going to promote a lot of capital efficiency.

Appreciate that. And my second question is just, you talked, Travis, about the macro environment and kind of eschewing growth in favor of returning on -- capital to shareholders over time. It seems like with this fixed dividend increase, you guys are signaling that this is sort of a sustainable level at a $40 price and below, maybe mid-30s to $40.

Considering now that we're in almost a $55 to $60 environment, does anything change operationally? You guys responded to a low-price environment by coring up your activity. I know that you're not interested in growth at this point, but do you change the design at all at the field level and perhaps not core as much as you have been?

No, David, it's -- we can't pay attention to weekly changes in commodity price. We have to try to do the best thing, the right thing from a reservoir performance all the time. And we're not getting enamored or stars in our eyes with higher commodity price.

Yes. No one ever blamed you for drilling wells that are too good, David.

Our next question comes from Scott Hanold of RBC.

And maybe I'm going to follow-up on that last line of questioning. Obviously, it's -- commend you guys for sticking to the plan with maintenance this year, but there's a lot of potential for an oil super cycle. And if that does occur, like how do you see Diamondback in a -- like a 2022-plus outlook? And is there going to be a limit to the amount of growth you could push?

I would assume that there's going to be some amount of growth that you would see acceptable given the amount of free cash flow that's out there. If you could just give us some color on, is it a reinvestment rate you'd target? Is it a growth rate or free cash flow yield? How do you look at a much stronger-for-longer oil price cycle?

Well, Scott, I think that will be a good problem to have. So hopefully, we're on our way. But I think we've been pretty clear that we don't want to put a very complicated business into a box in terms of reinvestment rate, growth rate. I think what we can say is that if there was ever growth called upon by U.S. shale, it would not be double digits. It wouldn't be 0. But yes, there is an oil price where your free cash flow increases more if you grow slightly.

And we've done that work. I still think we're a ways away from it, but we've proven that we can grow in the past. And I think a low-cost structure benefits you when prices are weak, but it also is a kick-starter to potential growth if prices are strong. So I don't think it's time to talk about growth, but if there was growth ever mentioned for us, it's sub-double digits or mid-single digits.

Yes. Just to reemphasize the point I made earlier about we're still in an undersupplied world. And yes, we can see the tealeaves talking about a super cycle, but that's not where we are today. I think just in the final analysis, Scott, growth Diamondback, we'll have to see a fundamental shift in the macro supply/demand. But future growth is not something we're scared of. Now as Kaes pointed out, hyper growth is probably still not a role.

But growth when it drives incremental shareholder returns is part of our long-term decision metrics. But right now, we simply don't need to grow, right, with this much excess storage and still production capacity out there in the world. But I think trying to put ourselves in a decision straitjacket is -- anticipating an oil super cycle is not a good business for us right now.

I appreciate that response. My follow-up is a little bit on current production rates. And if you could help me out a couple of things. I guess, first off, you talked about holding the line on the Diamondback legacy assets around 170,000 to 175,000. Obviously -- you kind of cited at fourth quarter levels, obviously, you guys outperformed that. You outperformed that in January as well.

Just giving a little bit of color on what do you mean by holding 170,000, 175,000 flat when you're, for all intents and purposes, above that rate. And if you can give also some color on what we should expect with QEP when it starts with you guys. And understanding that the last sort of like data point update was back in the third quarter of 2020.

Yes. Scott, I'm going to let Kaes answer that. But I just -- you provided me an opportunity to talk about how pleased we are with our operational performance. We saw it in the fourth quarter. We saw it in January. And had it not been a historic 100-year storm out here in the Permian, February would be looking good as well. So really pleased with the way that we're executing right now on our operational performance.

Yes. I think, Scott, we're looking to keep production guidance and CapEx guidance very simple. I mean, I think we said we're going to work our way up to 170,000 to 175,000 oil by Q4. Luckily, we outperformed that, but that was going to be the baseline for our plan in 2021 all along. And if we outperform that plan, then that's some for the good guys.

So overall, nothing has changed in terms of our anticipation of keeping Guidon, plus QEP, plus Diamondback flat through 2021. And in this guidance we've put out, we're basically giving you, saying, at 170,000 to 175,000 plus 10 months of Guidon out of -- at 12,000 barrels a day and a little storm impact, which we expect to make up throughout the year.

Okay. And what should we expect with QEP? Obviously, the last update was, I think, at the third quarter average. What is the expect -- like do you have a sense of what that looks like when it starts up in March with you guys?

Yes. I can't give you that today. I mean QEP is going to report, I think, today or tomorrow. And we'll see what that report says, and we will surely update the market as quickly as we can. But I can't give guidance on a deal that shareholders need to vote on.

Our next question comes from the line of Scott Gruber of Citigroup.

So the dividend increase here, one of your peers is dimensioning their comfort level with the base dividend as about 10% of operating cash flow at their normal crude price. Can you provide some color on how you think about the appropriateness of the base dividend for Diamondback?

I mean I think that will be a good goal to work to. Ours is a little lower than that in a $50 world and certainly lower than that at strip today. I kind of see it as more what's our consistent dividend growth rate over a longer period of time? And what are we doing to decrease the size of the enterprise value with free cash flow? I think right now, this dividend increase came a little early, but we also leaned into the dividend in 2020 during some pretty dark times.

So I think investors have universally asked us to hold the dividend and continue to grow it consistently. And while 7% is our lowest growth rate of the past couple of years, I don't think it's off the table that we can revisit this -- the dividend multiple times a year now at this point where we are.

Got you. And then just thinking about the budget split across the Midland and Delaware, 75% to the Midland this year. Can you just speak to the medium-term split? Thinking over the next kind of 2 to 4 years, are you going to stay in that ballpark of around 75% to the Midland post the acquisitions? And how should we think about, if we are back in an environment where you're starting to grow some, call it, mid-single digit, how does that split start to shift, if at all? And does the Delaware provide more of the flex in the budget?

I kind of see it more as we're going to have a really large block in Martin County that we can put a lot of rigs to work pretty consistently so long as we have the infrastructure in place, and we expect to do so. So I think with QEP, pending that deal closing, that 75% Midland number is going to go up, and hopefully, it stays kind of in that 75% to 85% of lateral footage consistently for the next 3 to 5 years. I think that's a little lower percentage of total capital, but it's going to be a pretty high percent of our net lateral footage for a long time here.

Our next question comes from the line of Derrick Whitfield of Stifel.

And as many have said before me, thanks for taking a leadership position for the sector with your ESG initiatives.

Thank you, Derrick.

With regard to your potential investment in CCS to offset your Scope 1 emissions, would you likely do that in concert with EOR? And if so, have your teams evaluated the application of EOR in any of your interventional project areas?

Yes. Derrick, I mean, that's one of the pillars that we're looking at. I can't commit to anything today. But I think what we've tried to say is that the credits that we purchased here give us a little bit of time to study the market or even partner on projects at either Diamondback or Rattler to build out a more direct offset to our Scope 1 emissions.

So that's in the fold. The hot topic of wind and solar power in Texas is also in the fold. And I think there's going to be a lot of opportunities with companies with large balance sheets that are leading this energy transition that are also oil and gas companies. So I think we're going to play a small part in it and hopefully find a good partner to develop carbon capture or one of these other renewable sources to offset our Scope 1.

But Derrick, I'll also add that while we don't -- there's not specific EOR projects underway, with 85% or 90% of the oil still left in the ground, even with the most advanced completions technologies, we know that enhanced oil recovery is a part of our industry's future. And there are some guys out there kind of on the leading edge that Diamondback, as our style, we're following very closely to see if they're having success.

But it would be nice if those 2 things were -- had the same mutual objectives: carbon sequestration and enhanced oil recovery and tight horizontally developed shale resources. But as Kaes pointed out, we're just barely getting started on that.

Makes sense. And with my follow-up, shifting over to the capital side of your outlook. Could you offer any color on a clean maintenance capital estimate, assuming the inclusion of QEP and based on your current cost expectations?

I mean it's kind of what we gave. I mean QEP has put out some high-level numbers on their full year 2021. So I think it's fair to look at those numbers. Now if you think about us closing the deal in March, we'll only have cash CapEx for 3 quarters of that. But at current cost estimates, like I said, I think the midpoint of our guidance is 8% to 10% above where current well costs are. So if we stay the same, you could chop 8% to 10% off of that and get a solid maintenance number.

Our next question comes from the line of Jeoffrey Lambujon of Tudor, Pickering, Holt.

My first one is just on the M&A and A&D landscape. I know it may be a little too soon to talk about what opportunities both transactions could bring since the QEP deal is more expected to close next month. But are there any comments or thoughts you can share on how the landscape looks to you all in areas where you may be active once everything is rolled in? And then any comments on industry consolidation more broadly from here, especially following an active 2020 would be great as well.

Yes. I'll let Travis talk about the macro. But just in general in A&D, we've been following it pretty closely. I think there's a lot of capital that's been allocated towards PDP-type transactions, which bodes well for any potential deal we look to pursue in the Williston, for QEP's Williston assets. It seems like that's the hot A&D market of the year so far. So we're excited about that. Commodity price certainly helps.

We have some small stuff that we would look to sell in the Permian that's fully developed that doesn't compete for capital and that market looks pretty good. So we're excited about A&D. I think from a consolidation perspective, a lot of big consolidation happened in 2020, obviously. And you can just see now how much production is in the hands of 10 to 12 companies in the U.S., and I think that bodes well for capital discipline and industry consolidation, although I think it still needs to continue. Travis?

Yes. What we've seen in the past, Jeff, when we go through one of these cycles of rapid commodity price increases, names that you would have thought would have come off the board -- public names that would have come off the board, probably now have a lot greater runway with the higher commodity price. So usually when you see these kinds of cycles accelerate, it makes, from a macro perspective, A&D harder to do. But just like Kaes was saying, though, we've got Guidon and soon to be QEP to roll in the mix, and we're very comfortable with where our inventory sits right now in terms of runway in front of us. So I just want to add that in as well.

Appreciate it. And then my second one was just on hydrocarbon mix as the newly acquired assets are rolled in. Just wanted to get a sense for how you'd expect the higher weighting for Midland activity, which I guess should increase further once QEP is more fully rolled into effect oil and gas mix over the near term.

Yes, it should help a little bit, 100 to 200 bps of oil mix. I think that's why we started guiding to oil separately from BOEs. The BOEs continue to outperform, primarily because flaring is down 5%, which has resulted in a lot higher BOE numbers and BOE reserves. So Midland certainly is oilier and moving to Midland, Northern Midland is going to help. But the production base is pretty large right now. So I think it's in the range of 100 to 200 bps, not more than that.

Our next question comes from Brian Singer of Goldman Sachs.

Travis, you've been very forceful on the capital discipline side, not using incremental cash flow back to the drill bit, focusing on paying debt and incremental return of capital to shareholders. You do have exposure and through your partnerships to what others are doing. And I wondered, given some of the rig increases we've seen from private producers, if you have any perspective on what you see others doing and if you expect other operators in the Midland and Delaware basins to reflect the discipline that you're expressing here.

Yes. Brian, I think -- I know you're asking those questions to those individual operators. But from a macro perspective, what I'm seeing is that we still are undersupplied on rigs to keep the Permian Basin flat. So you may see some rig adds coming, but right now, it's probably not enough to offset the production declines that we've seen through the lack of investment over the last 12 months.

So I believe, and maybe I'm the eternal optimist, but I believe if moving through the depths of a global apocalypse that was created by this pandemic, if oil and gas companies haven't got discipline now, they probably never will. So I'm optimistic that the industry is going to toe the line on capital discipline, irrespective of commodity prices.

Now there will be, sometime in the future, a signal when supply has worked off and Iranian barrels are absorbed and surplus OPEC capacities has consumed that the world will be signaling for growth. But as we tried to articulate earlier, the days of hyper growth in the shale industry should be part of our history, not part of our future.

But I'll tell you, just adding to that, and I know you guys get tired of hearing me talk about our operations and our low cost, but as the low-cost producer, almost irrespective of commodity price, we're going to drive the highest returns to our shareholders.

Great. And then I wanted to further follow-up on the carbon Net Zero objective and particularly on the sequestration and clean energy comments that you made. When you think about expanding the Diamondback footprint into sequestration or clean energy, do you see these as core competencies the Diamondback team already has? Core competencies the team can easily bring in-house? Or should invest along with others to fund existing companies that have that core competency?

Yes. No, Brian, I don't see those core competencies inside Diamondback, and it's unlikely that we would branch out into trying to say that we can become a better solar company or a better wind farm company than pre-existing. I think that's actually a trap that some companies get into as they try to diversify into areas where they're not experts.

We at Diamondback know what the main thing is and the main thing is, is for us to produce barrels at the highest cash margin, with the lowest cost and now the lowest carbon footprint. So I think the most likely scenario would be that we participate alongside a subject matter expert in whatever that carbon capture technology is.

Our next question comes from the line of Richard Tullis of Capital One Securities.

So just continuing with the Net Zero initiative discussion. So just listening to everything this morning, so is it fair to say you may be initially more interested in the carbon capture side of CCUS rather than the CO2 transportation and sequestration side?

Richard, it's just too early, right? I think we're getting away from the fact that the goal is get Scope 1 down by 50% as soon as possible and get methane down by 70% as soon as possible on the intensity side. And those remain the focus, right? I think getting into other businesses is a 3-, 5-, 7-year discussion. But the discussion today is what are we going to do to get our carbon footprint down and not just offset it, right? I think eventually, offsetting it with something smart in terms of an investment, a small investment, but it's not going to end up taking 10%, 15%, 20% of our budget.

I think, like Travis said, the main thing is the main thing, and that's we're an oil and gas producer that's going to be producing here for a long time. But as a public operator today, the pressures to operate in an environmentally responsible manner are only going one way, and we're taking the bull by the horns by getting those intensity numbers down as soon as possible.

Yes. Richard, we're not trying to buy our way into carbon neutrality. We're trying to be very specific. You can see on Slides 12, 13 and 14 in our investor deck how much transparency we're using to try to describe exactly what we're going to do. We've been very prescriptive in talking about 600 tank batteries that need to be retrofitted and spending $10 million to $15 million a year over the next 3 to 4 years in order to make that happen.

So our focus is not to try to buy our way into carbon neutrality, our focus is how can we invest to eliminate our Scope 1 emissions. And the carbon credits now provide us a bridge and, quite honestly, provides us an incentive, because I don't like spending that money, but it provides us an incentive to get the operations in the shape that they need to be. And that's what we need for our shareholders, and that's what our industry needs as well, too. And I hope other companies can take a similar examination of what efforts they're doing to reduce methane emissions, particularly.

Our next question comes from Paul Cheng of Scotiabank.

I have to apologize first. I may have joined a little bit late, you may have discussed it already. You raised the regular dividend. And you also mentioned that in the future, once your debt has come down further or that positioned better, you will look for other alternative ways that to increase the share distribution. So I wanted to see then, what is the precondition for that? What kind of debt level or that any kind of criteria you could indicate? And also can you discuss your preference between the variable dividend and the buyback? Or that the regular dividend increase will be the primary source of the distribution?

Yes. Paul, that's a good question. I think a variable or a buyback are things that are worth discussing when debt levels are at a level that we're very comfortable with, which is probably close to 1x leverage at $45 to $50 WTI. So I think once we're closer to that range, we can talk about additional return to capital, which is kind of why, earlier in the call, I mentioned that anything with a maturity prior to 2029 in our debt stack is probably up for grabs to pay down in conjunction with continuing to increase the dividend.

But as soon as we get there, I think it's a worthy topic to say what is the best return to shareholders post or after the base dividend and when debt is very comfortably in that 1x range. But first and foremost, we need to get our debt back down to $5.5 billion gross debt pro forma for all the deals that we've just done, and we'll be getting there as quickly as we can and continue to work that down.

Our next question comes from Leo Mariani of KeyBanc.

Just wanted to follow-up on one of the comments you made earlier. Kaes, I think it was you that said in terms of purchasing the carbon offsetting credits, it's going to be some type of mid 7-figure number. Just wanted to clarify, is that an annual number, roughly speaking, for you folks? And it sounded like you also talked about this transition time line kind of being 3 to 7 years. So should we expect that kind of for the next 3 to 7 years? And is that something that would just kind of run through as an operating expense in your financials eventually?

Yes. Well, it's highly dependent upon how many tons of CO2 equivalent we emit, right? I mean in 2019, we emitted 1.4 million tons. I think we'll be well below that in 2020 and on to 2021. So the cost goes down. Now if I was a betting man, I'd bet that carbon offset credits are going to continue to increase in price. We've secured a few years' worth right now, but I think it will be dependent upon what that -- how that market evolves over the coming years. But again, it's not a material expense and it's not the priority. The priority is getting the amount of CO2 equivalent emissions that we have down so that you pay less of a penalty.

Okay. Great. And obviously, you guys are clearly in the midst of closing the QEP and Guidon deals in the near term here. Travis you briefly addressed M&A earlier. But as you get to your target debt number here in the near future, do you still have a desire at Diamondback to continue to be a consolidator of choice in the Permian?

Yes. Look, Leo, we're very comfortable with where we are right now, particularly with these 2 deals closing, one Friday and then one in a couple of weeks after that. So we're very comfortable where we are. And we'll just -- like we always do, we monitor the landscapes and if we think we can deliver outstanding returns to our shareholders, then we'll take a look at it. But in terms of inventory life and all of that, we're very comfortable with where we are.

Our next question comes from Charles Meade of Johnson Rice.

Kaes, I think maybe this question might be for you. I appreciate you gave us a really pretty thorough rundown of your debt paydown options and you gave us a good framework. I'm wondering if you could refresh us a bit with your thinking or your options on the QEP debt, in particular the '22s and '23s, and how that might play into your debt paydown plans.

Yes. It's certainly a chess piece, Charles. I think QEP has 3 notes outstanding, '22s, '23s and '26s. Those notes probably end up getting tendered for and refinanced in some form or fashion, lower interest rate with longer average maturity, but also putting something on the front end of our debt stack to guarantee further debt paydown.

So it's really dependent upon how many people tender the bonds if and when that begins. I think the FANG 2025 notes is also a chess piece that goes into that. And I think we're pretty close to starting that process with the shareholder vote coming up in March 16. So we wanted to take advantage of these rates with 3 goals: we want to pay down gross debt overall over time at our discretion, we want to lower average interest rate and we want a longer average term to maturity. And I think we're setting ourselves up to accomplish that.

Got it, Kaes. So if I understand you correctly, it's not committing to one path or another, but really just kind of continuing to pushing optimization and finding -- picking your spot?

Yes, with the caveat that we do need to work on some restricted covenants and some reporting requirements on the QEP notes because we don't anticipate reporting as 2 separate companies for a long time. So I think Pioneer, Conoco, Chevron have all followed different -- or similar paths in handling the notes of the company they acquired, and we're going to copy one of those paths.

Got it. That makes sense. And then, Travis, this is perhaps for you. I wonder if you could characterize the assets that you're picking up in Southeast Martin County or towards the -- in the southeast quadrant, that's -- could you characterize how prominently do those factor into your 2021 plans? And to the extent you are going to put some rigs there, when would we expect to see some results from those assets?

Look, I mean we're going to add one rig net for the Guidon deal, and that rig is going to drill a 10- or 12-well pad here throughout the year, and that pad is going to come on early next year. And then I think -- I can't speak to the QEP development plan, but I think as soon as we can move rigs to that big block in Southeast Martin County, we're going to move 2 or 3 rigs there and be active there for the next 5, 7, 8 years.

Your next question comes from Jeanine Wai of Barclays.

You're probably going to kill me, my questions are on the ESG and Net Zero Now initiative. But maybe just 2 quick ones. We know you've made it clear that you're not looking to buy your way out of emissions or anything like that, and the credits are really just a supplement to your good internal efforts. You mentioned you have some contracts in place for CCS, but in terms of the other options, what are the different markets that you're looking at in order to potentially buy offsets? I mean we're thinking it's not California. We know Texas has an exchange market. And are you currently eligible to participate in all of the credit markets?

Yes, we are Jeanine. And we're pretty focused on U.S. carbon credits versus international. International, you can get a little cheaper, but I don't think that ties directly to our license to operate in the U.S. So the couple of projects that we've invested in, 2 of them are based in Texas, 1 of them is based in Wyoming, and that's our start. I think we're going to build a good relationship with our partners on this and eventually work to invest directly. But I think overall, with us executing on this initiative, there's going to be a lot of inbound phone calls on opportunities. And I just think our goal is to make sure what we do invest in ties more directly to what we produce rather than other environmental aspects.

Okay. Great. Very interesting. And then maybe just following up on Brian's question earlier. I know you're not looking to be a merchant power player or anything like that. But you're looking at both in-house and third-party opportunities, it sounds like, for the income-generating projects.

So not to get ahead of ourselves, but we are. Longer term, could this be maybe carved out as a separate business if you develop a portfolio? Because it seems like for a lot of these ESG projects, companies kind of really only get credit or a lot of interest when it turns into like a real business that investors can quantify. And longer term, there's been lots of spin-offs and opportunities for that. So is that something that maybe you would consider?

I mean I think we're getting way ahead of ourselves, Jeanine, on that. But I think we've proven to be pretty smart when it comes to spin-offs, but I think my head might explode if we thought about another spin-off right now. So we're going to just, first, get our numbers down; second, invest smartly or wisely with bigger partners; and then third, figure out how to monetize down the line. But certainly, we're very cognizant of the multiples that, that side of the business gets versus an oil and gas company right now, but that's not the reason why we're doing this.

Yes. Jeanine, we want to make sure we emphasize keeping the main thing the main thing. I said that earlier. And we know what we're really good at and we know what we're still learning at. And we're going to focus on what we're really good at, and we'll participate alongside someone that's really good at something else. And as Kaes said, for another fourth company or fourth entity, that's not -- that doesn't sound very good to me right now. So I think our focus is going to be doing the right thing for Diamondback operations to drive down our emissions intensity.

At this time, I'd like to turn the call over to CEO, Travis Stice, for closing remarks. Sir?

Thank you. Occasionally, I'll use my closing remarks to add a message that's kind of directed towards our organization and a message I think sometimes important for our investors to hear that separates from sort of the standard quarter.

This past week, as we're all acutely aware of, the Permian Basin experienced unprecedented weather event. We had over 220 hours of below-freezing weather. And really across the Permian Basin, we had extended periods of no electricity and water supplies frozen and really, against all of that, we had a frozen and a dark oilfield. And our field organization, and in some cases, these individuals working over 20 hours a day, they were working to get gas delivered to power generation plants. They weren't working to get Diamondback's volumes flowing and back online earlier because of our quarterly objectives. They were working to get gas delivered to power generation plants that were -- honestly, that were sitting idle, particularly on the west side of Odessa. And they were sitting idle because they didn't have any fuel.

And through our efforts and other operators' efforts, gas was delivered and Texas had power. This occurred Wednesday evening, early Thursday morning. And by Thursday, most of Texas, again, had power. And it's -- I just want to -- the efforts that were displayed by many individuals in the Permian Basin transcends normal procedures for returning production. And the Permian Basin is grateful for -- we're really grateful for everything that you guys did. You answered the call and you put forth a heroic effort that will not be forgotten. Just want to tell you publicly, thank you for everything that you guys did.

So with that, thanks for everyone participating in today's call. And if you've got any questions, please contact us using the contact information provided. Thanks, Latif.

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