Q3 2023 Diamondback Energy Inc Earnings Call

November 7, 2023

Good day, and thank you for standing by.

Welcome to the Diamondback energy third quarter 2023 earnings conference call.

At this time all participants are in a listen only mode.

After the speaker's presentation, there will be a question and answer session to ask a question. During the session you will need to press star one on one on your telephone you will then hear an automated message advising your hand is raised.

To withdraw your question. Please press star one on one hand.

Please be advised that today's conference is being recorded.

I would now like to hand, the conference over to your first speaker today, Adam Lawlis VP of Investor Relations. Please go ahead.

Thank you Steven good morning, and welcome to Diamondback Energy's third quarter 2023 conference call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondbacks website.

Representing Diamondback today are Travis Stice, Chairman and CEO, Keith fans, Hoff, President and CFO and Danny Wilson.

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.

Caution you that actual results could differ materially from those that are indicated in these forward looking statements due to a variety of factors.

[noise] formation 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 will now turn the call over to Travis Stice.

Thank you Adam and good morning to everyone as Adam mentioned, we released the shareholder letter last night that contains much of the narrative. We hope to cover again. This morning, so with that I'll just open the lines up for questions operator.

Alright. Thank you at this time, we will conduct a question and answer session. As a reminder to ask a question you will need to press star one on your telephone and wait for your name to be announced.

To withdraw your question. Please press star one again.

Please standby, while we compile the Q&A roster.

Our first question comes from the line of Neal Dingmann of <unk> Securities. Please go ahead.

Good morning, Travis and team thanks for the time and another nice quarter try. This is my first question is on capital allocation specifically.

Several quarters ago. You suggested you all would return to more of a production growth type model I call. It and I think you've mentioned the macro fundamentals supported I'm. Just wondering do you believe we're close to that scenario and wondering why do you believe that.

The continued high free cash flow payout is warranted.

Yes, Neil that's a good question look the world is certainly in a mess right now across any number of fronts.

All of which could potentially move to markets, both positively and negatively negatively both with a supply disruption or even a demand destruction as well too.

Obviously, we can't control any of those items again, we simply respond to our shareholders that own our company that right now return to shareholder model versus a growth model as we've estimated our plans as we look forward into next year.

Again look for real efficient capital allocation and the output of that capital allocation, we expect low single digit type volume growth again, not as an input, but what results from an efficient capital allocation program.

Got it that makes sense in this environment and then secondly on your development Couldnt help but notice the new slides on slides 10, and 11 highlighted the efficient execution and then to the differentiated development. My question is does most of your remaining Midland inventory led to the 24 average wells.

Wells per project size that you mentioned and then I'm just wondering could you speak to where the largest cost efficiencies continue to come from on these projects.

Sure on the development strategy overtime slide which is slide 11 for those of you that are looking at it online we tried to demonstrate.

Our evolution from 2015 to today, and we said average wells per project is about 24 wells.

Generally that's that applies across our Midland basin, However, not all.

Posits are equal.

Terms of the way the shales were laid down across the Midland basin. So there will be areas, where we can do slightly more than 24 wells.

And then there is also where we will be slightly less than 24 wells, which usually translates to one or two wells less per shale intervals. So again, it's a general representation showing the.

Element over time.

That's a good that's a good summary.

And then.

What was your second question first on the cost on the cost cadence and I've talked about I mean is it just on.

I know you have lower KC, and just different sort of raw material costs, but is there is there are others.

There is in that larger projects that are causing these.

When you see that well productivity chart on the right.

Sort of what's driving the lower cost efficiencies there.

Yes, certainly again referencing back to slide 10, we've laid out the biggest elements of cost savings cost components and the reductions over time and as again as you pointed out is casing, which is down 20% or so.

It's really as you look into look into next year.

We feel more of a kind of a steady state run rate on our cost there'll be some puts and takes on both sides of the equation take Q&A I think the biggest benefit to these large scale development Neil as you know.

The consistency of running rigs in the same spot for a longer period of time, but on the frac size, where we pay the most money from a capital efficiency perspective, because we're doing and in some cases two simultaneous crews on a same site at the same times year saving essentially 250 $300000 of wells.

From simultaneously and now we add two of those fleets are E fleets that runoff lean gas and save kind of another 200 $250000 of well so and this large scale development kind of ties to the longer cycle nature of our business and that also means we don't want to change the plan.

Every move in oil price and so we've.

<unk> had a consistent plan here for a few years now and the output of that is consistent results on the on the well.

On the well productivity per foot.

Thank you both.

Thanks, Tim.

Thank you one moment for our next question.

Our next question comes from the line of Neil Mehta of Goldman Sachs <unk> Company. Your line is open.

Great. Thanks, guys and I appreciate the helpful letter and the time today that perhaps when we start on return of capital as a topic you talk about the ladder and wanting to err on the side of caution as it relates to buying.

Buying back stock to avoid repurchasing pretty quickly and as a result leaned into the variable dividend in the last quarter can you talk about.

The way that Youre approaching this and how that Chad.

Inform the way, we think about the split between buybacks and dividends going forward.

Sure.

Our main focus remains.

Sustainable and growing base dividend that we think represents the most.

The most efficient way for our shareholders to understand what our shareholder return program looks like following that is the share repurchase program, which we laid out what we've done in the third quarter and so far in the fourth quarter and then we honor our commitment to return at least 75% of our free cash flow Bob.

Making our shareholders hold in the form of variable, which we see.

We did this year I think the most important thing is is when you talk about share repurchases is that you need to have some discipline around that because in my experience lack of discipline leads to chasing stock repurchases all the way to the top of the cycle. So we like most of our capital allocation decisions.

Like all of our capital allocation decisions, we hold ourselves accountable to some form of rigorous analytics and in this case, we continue to run and add value at mid cycle oil prices, which is $60 oil and calculate oil price or calculate stock price and depending on where.

Where our stock is trading relative to that calculation, we either buy more of further.

This location will get from that we buy.

We increase or.

If not then we pivoted to.

To share revert to a variable dividend.

This time around so.

Again, it just it's base dividend and share repurchases.

With a degree of caution in our prostate clinical environment, and then honoring our commitment through the form of a variable dividend.

Okay. That's really helpful and the follow up is just on noncore asset sales we've done a good job of exceeding your target can you talk a little bit about that.

The deep Blue Midland Basin, JV, and then not only in terms of the proceeds but what does it mean for your go forward cost structure.

As we think about modeling the impacts through 2024.

Yes, good question, Neil the deeper JV.

Very big deal for US It took a long time to to pull together, we have built a significant amount of midstream infrastructure over the years and it's been a lot of capital doing yet and we felt it was an opportune time to monetize that in the hands of <unk>.

We see his operational expertise and deep blue in the five <unk> I think they have already proven to have commercial success with third parties, where.

Maybe if you haven't gone into that business card you weren't going to have the same type of commercial success.

I think.

That sector is certainly ripe for consolidation as well and I think they are the experts that can get that done. So that's kind of why we retained the 30% equity interest in the business, we're very confident that they're going to be able to grow the business and generate a good return for our shareholders.

Outside of the $500 million proceeds we got in which a debate the big the big winner there will be some impact to our cost structure I would say generally.

LOE is going to be up about 8% to 10% versus prior as a company and then.

We will have a lot less midstream capex is we don't have any operated midstream assets and that will be kind of canceled out by <unk>.

Slightly higher well costs $10 $10 to $20 a foot depending on the area as we buy water from the JV. So all in all we saw the business for a much higher multiple than we trade and we're excited to see what they can do in terms of creating value for the 30% that we're retaining.

Thanks, Tim.

Thanks Neil.

Great. Thank you one moment for our next question.

Our next question comes from the line of David tackle bomb of TD Cowen. Your line is now open.

Okay.

Good morning, Travis and case team Danny Thanks for taking my questions.

Travis I was curious if you could talk a little bit more.

About the remarks in the shareholder letter on being an acquirer and exploit or.

And just maybe putting in context sort of.

How robust do you think that opportunity set is right now just given the cycles in the business and some of the cycles that have gone through the Permian right now.

Yes, David and I appreciate you're referencing the shareholder letter I tried to address that head on I think just in a more macro sense, we'll always do what's right for our shareholders and when we've got now over over a decade of what I think is demonstrating to doing the right thing for our shareholders, but we remain laser focused on.

Delivering on our business plan and Youre right. We have built this company through <unk>.

<unk> explored strategy.

But I think as investors really started to understand we have such a high quality inventory right now that the bar is pretty high for additional opportunities to add too.

Add to our inventory that meets those.

The criteria that we laid out in our shareholder letter with sound industrial logic, and being able for logic and being able to compete for capital right away and then and then being accretive on those financial measures that are so important to all of it so.

There has been a lot of private equity roll through and and I think based on based on lack of our name on those it just as you were we view those assets relative to our inventory like I like I said I'm really pleased with the quality of our inventory and I think I think we're executing on that.

Wallace manner.

I appreciate that.

Maybe just for case.

The DUC backlog is built I guess up to a 150 by the end of the year.

You guys talked about.

Low single digit organic oil growth for next year.

One I just wanted to confirm.

That oil growth is reflecting the benefit of the increased royalty interest through the bandon acquisition or Viper acquisition rather.

Or that's.

How we should be thinking about that growth rate and then just in concert with the DUC backlog.

Or is it should we think about that flexibility, especially in this pricing environment just based on Frac crew availability or is that really just like a capital allocation decision.

Yes.

It looks like organic growth comment first certainly.

Excluding the LIFO deal, we expect it to grow organically.

We expect to grow organically in 2024 I.

I think the Viper deal provides a little bit of a jump start here in Q4, but I think the team is expecting to grow off that number.

Steady state throughout the next year.

Just due to the quality of what we've got in front of us on the DUC side, we were kind of operating pretty close to the rigs on the completion crews.

They needed some.

Some flexibility here in the drilling team has done a really good job. This year getting ahead of plan drilling more wells than expected sooner.

But these are these large pads in large projects.

We want to have the flexibility to be able to go somewhere if something.

Something bad happens and that DUC backlog allows that so I think $1 50, plus or minus 10 or 20 wells.

Either way is a pretty good number for our run rate and we've kind of set that set the stage for a world where we run for these simultaneous cruise consistently throughout the year. They each do about 80 wells a year and you know in our mind, that's kind of the most capital efficient development plan. We can we can imagine here.

So that's our backlog just less any sleep a little better at night.

It allows for some flexibility heading into next year.

Okay, Neil Thanks for the responses.

Thanks, David.

Alright. Thank you one moment for our next question.

The next question comes from the line of Scott Hanold of RBC capital markets. Your line is now open.

Yes. Thanks.

If I could.

Go back to the M&A topic, a little bit differently.

<unk>.

Keith Travis when you step back and think about like where <unk> inventory depth is and to be a long term successful large scale play in the Midland.

Do you think that more large scale M&A is necessary over time, and just remind us like where you think your inventory life is and where ideally would you like it to be.

Yes, I mean, I don't think its necessary Scott I think we've positioned the business.

They are both large scale and small scale M&A just kind of been in our DNA for the last 10 years.

And kind of go back to.

Thinking about what positions in North American shale or in the Midland Basin with the Endy and there are very few particularly with where we sit today and the amount of deals we've done over the years. So I think it's I think it is.

A fortunate spot to begin with the inventory duration and depth that we have relative to whats out there.

I just think <unk> comment is really about knowing who you are and this company has been a acquire and exploit company that's been able to execute on acquiring and exploiting assets through our low cost structure and generally we are not a philosophy that the low cost operator in a commodity based business wins.

Our cost structure is what has created.

This business to be as big as it is today Charles anything to that I think that makes sense.

Talked about the high bar for entry into.

And in the Diamondback portfolio and.

That's just how we view it and we're very we're very proud of the inventory we have and I think what goes along with that durable inventory is how we convert that inventory into cash flow and again <unk> seen this quarter.

Flawless execution from our teams and converting rock into cash flow.

Our cost structures enviable.

Our execution prowess is unmatched.

That makes that makes a big difference when you talk about a profitable oil and gas company like Arizona.

And then just and just as part of that was the inventory life kind of conversation more of like where you think you are at now and where do you think is ideal.

Yes, I mean I think okay.

This put our next five years up with anybody and in.

In North America, I still stand by that.

We have another solid five or 10 years beyond that it's very logical that at some point youre going to have to move down the quality of our inventory.

We don't see that in the floor plan today, but if we retain our cost structure and our ability to drill wells, one or one five for $2 million cheaper well as the shale cost curve goes up we continue to stay at the low end of that cost curve, that's kind of been our.

Our mantra for 10 years, now and we started with <unk>.

1000 acres and our at $5 50 and.

That culture, and mantra has not changed and I think that sets us up well for a world.

Where assets are getting more more and more sparse.

Got it understood and if I could follow up on.

Our conversation we had last night just on the shareholder returns.

Stock buybacks and I thought it was an industry conversation, we had on just where things intrinsic value is now and the opportunity to grow that over time.

So like when you step back and think about the current oil market. Obviously, we're in a little bit more heightened oil price versus your intrinsic point Budd Lake is as you see yourself progressing over the next years.

Does it seem to make sense that buying it buying back stock at higher prices in this heightened market relative to what you did in the past still make sense from a value return standpoint.

Yes, it's really all about all about value and I think we talked about last night. If you run your business conservatively from an oil price perspective, and accrete value quarterly.

At 75 to 80 to $85 crude.

Youre actually building equity value.

On a conservative basis, right I kind of said last night to you that.

Generally if you run a quarter like last quarter versus the $60 base case, you're basically building $304 a share of extra intrinsic value and I think that's what we've done here over the last couple of years and this upcycle and.

Travis mentioned, we want to be conservative on buying back stock, we think capital is precious and capital discipline not just supplies in the field that it applies.

Returning capital to shareholders and that's why we've had this flexible return of capital program since we put it in place two five years ago.

Thank you.

Thanks Scott.

Alright. Thank you for your question one moment for our next.

Our next question comes from the line of Roger read of Wells Fargo Securities. Your line is now open.

Yeah. Thanks, good morning.

I think.

I think I'll skip the obligatory share repo versus variable dividend question for a moment just.

Go back to the operational aspects. So can you give us an idea as you mentioned the sort of accretive value into the shares through operations, what we should be looking at over the next say 24 to 36 months for what else you can do operationally that will accrete value and <unk>.

<unk> that we're not going to have some of the asset sales that have been going on and that has certainly helped on the sort of cash flow generation assets.

Yes, that's a good question Roger.

It's interesting.

Slide in slide 10 about operational track record and prowess and I.

I think we've sat with sat in this room, two or three years ago, saying, hey, the drilling guys there.

Near the asymptotic curve of drilling these wells well if you look at the top left of that chart Theres still taking days out of the average well on a much bigger program right. These guys are drilling 280 wells in the Midland Basin.

Three or four days faster than they were even two years ago.

The culture that we built it creates that value to our shareholders and not something remodel, but it certainly comes our way so in the field I think thats part of what is coming our way.

I also think.

Generally we've tested some other zones in the Midland Basin that looks very very good. We've got a couple of upper Sprayberry test in the northern Midland Basin that look very good relative to our middle Sprayberry Jo Mill development. So we're excited about that.

The Wolfcamp D and the Midland Basin is starting to become a primary development zone.

Some of the basin and certainly there's a lot of excitement about deeper zones.

In the Midland Basin, as well as the Barnett and Woodford that were on to testing. So I think the Midland basin, the stack pay and the amount of oil in place just just provides a lot of opportunity for.

Future value.

To increase our shareholders.

They don't know about today, Travis you want anything to that Roger.

<unk> 10 years ago. When we first started this we should we're still drilling.

Vertical wells and.

I'll put in the letter that we released last night, just a couple of data points on a 7500 foot lateral well, which has a total depth total membership of about what we were drilling vertically when we started but drilling.

We drilled those 7500 foot lateral wells in under four days and when we started we were drilling it sometimes it takes us over 'twenty four 'twenty five days to get down to that same measure depth vertically and so.

Probably the most repeated question that we get.

What is the secret sauce, what is the magic that Diamondback does that allows execution quarter over quarter to just far exceed the competition.

It's essentially the same rock and the same tools, but the culture that we've built here at this company with that laser focus on the conversion process of rock into cash flow.

<unk> fell by every employee in the company.

And when you have everyone's leaning in the same direction on cost and efficiency.

As long as we can continue to give them a good rock theyre going to we're going to generate the outstanding results that we're known for so.

Thats, a little bit of motherhood, and Apple pie, but it's.

I'm really proud of the organization for.

Through all the cycles, we've been through over the last 10 years, what Hasnt changed is an unrelenting focus on delivering.

Best in class execution highest margin barrels at the lowest cost.

I appreciate that I'm, not going to be down between motherhood and Apple pie here in the U S. So I'll turn it back.

Thanks Roger.

Thank you one moment for our next question.

Alright. Our next question comes from the line of Derrick Whitfield of Stifel. Please go ahead.

Good morning.

Thanks for all the incremental disclosures this quarter.

Thanks Derek.

Building on an earlier question, how should we think about 2020 for maintenance capital run rate, assuming the benefit of deflation and your current operational efficiencies.

That's a good question Derrick I would probably say that maintenance capex would be $1 million to $200 million cheaper.

30 wells, maybe Danny Yes, I think.

Kind of looking at it.

Our maintenance.

Our case for 2024 is kind of a maintenance activity K, so flat activity output a little bit of a growth but.

If we were to try and maintain a flat production profile, he probably being a line of 20 to 30 wells in the year.

While you're on that topic of maintenance Capex I might just point you to slide seven we've had that slide and there are a couple of times, but it shows maintenance capex, which as David just defined as kind of holding.

Fourth quarter production flat for next year and I just want to show you what our breakeven prices are on that slide $32, a barrel that cover maintenance cap maintenance capex.

$40 per barrel to cover our base dividend. So that's kind of goes back to my cost of execution comments that ultimately translate into a very protected business model, even at low at low commodity prices.

That's great and as my follow up with respect to the noncore asset sales how should we think about the market value of whats being retained by Diamondback and how that will be realized over time now that you've exceeded your disposal target.

Yeah. Good question, Derek we did lay out some of our remaining JV that we have on slide 26.

I think some of those logically or monetize at some point in the coming years.

I think we're in a huge rush to do so but.

In most cases, we're kind of.

Non op partner to these jv's.

Do you have a ton of value just not something that we can.

Commit to.

Monetizing today.

Well done guys. Thanks for your time.

Thank you <unk>.

Alright. Thank you one moment for our next question.

Our next question comes from the line of Kevin Mccurdy Pickering Energy Partners. Your line is now open.

Hey, good morning.

I appreciate the commentary on industry consolidation digging into your cost structure comments, a little bit now that you've had higher burden lario in house for most of the year can you comment on the level of cost synergies you've created in those transactions or maybe just share with us your analysis of diamondbacks costs versus peers I'm, just trying to get a sense of what kind of uplift assets gateway.

They are incorporating to diamondback in your cost structure.

Yeah. Good question Kevin.

I hate to say it but we didn't win those deals because we because we were buddies and bid less than other people. So I think we've hit the most but we missed the most because we can underwrite it with the lowest cost rate at the time.

I think some of the well costs were near 885 $9 $5 million for a 10000 foot lateral near drilling on the.

Six five to seven.

And so that's kind of been our our mantra for a long time.

I would just say generally if you split the two deals up l'oreal was a.

Execution deal because we knew we could we could drill those units cheaper and execute on.

Large scale development I would say Firebird is more of a technical deal and we had a technical view of that particular area that the basin could move further west.

In the northern part portion there'd be some multi zone development that looks really good I think we were conservative on the multi zone potential of the central block and now feel a little more confident about the wolfcamp, a and a lower sprayberry and any being wine racked in that area and also with the benefit of that block being so.

No contiguous we're able to.

Bring a 15000 foot lateral manufacturing process to that area. So we underwrite these deals that are in our cost structure.

Which if you look at our cost structure versus others that means we should get.

More of those properties at the same rate of return because of our ability to execute.

Great. That's that's the only one for me I appreciate taking my question.

Three questions Kevin Alright.

Alright. Thank you one moment for our next question.

Our next question comes from the line of Jeffrey <unk> of Tpa to <unk> Company. Your line is now open.

Good morning, everyone and thanks for taking my questions.

Thanks first one is on the ops and capital allocation side. If you can just speak to any more detail on next year's plan in terms of where you might focus within the Midland basin. Both in terms of geography, but also maybe just less active zones in terms of industry activity that you may be testing more and if you could speak maybe a bit more onto some of that lateral length commentary in terms of her.

How that might evolve over the near term program that would be helpful as well.

Yes, Jeffrey with these with these longer cycle projects, we have a pretty good view of what the projects look like coming up here in 2024.

I would say generally we're going to be in the range of 11000 feet average lateral length, probably maybe even a little bit more than that.

I would say, it's also a very heavy Martin County development year for US, which is which is great in a large large scale multiyear multi zone development in some of the best undeveloped resource remaining in the Midland Basin.

I'd say from a from a testing perspective, some of some more wolfcamp b, probably making it into the plan and a lot more upper sprayberry, making.

Making it into the plan.

Have a couple of really good test.

Part of our culture is when something works, we implemented very very quickly and that's how we kind of see the shallower development.

The pace in the northern Midland Basin, particularly that northwest Martin County area.

We feel really good about for adding a new zone.

Okay, Great and then maybe just a housekeeping type question on the noncore asset sales side, particularly on the upstream I think a few people noted now just how you're exceeding or you've already exceeded the target before year end here and it makes sense that there is no need to go out and do more right away, but just wondering if you can speak to potential opportunities maybe in terms of longer dated inventory.

Someone else might find more valuable and de risk how do you think about the opportunity set from here.

Yes, good question that ties to some of that didn't answering your last question.

The number of wells in the Midland Basin will be kind of $85, 90% of total capital for the Delaware Basin still be a small percentage of total capital I think if I'm getting what your question is where does the Delaware basin sit in the portfolio and I think I think for US certainly we started that area of capital.

A little bit here in the last few years I think it provides a lot of cash flow and a lot of production, which is beneficial to us today.

As you've seen over the course of the year. It certainly seems like inventory is coming at a premium and there may come a time, where someone really really wants that delaware position of ours or portions of it but we're not going to sell it for a song a song in PV 15, right PDP. So.

I think we're going to hold it for now and if someone wants to pay for upside and a reasonable.

Number versus where we trade, we'll take a look at it.

Perfect. Thank you.

Thanks Chip.

Thank you one moment for our next question.

Our next question comes from the line of <unk> Kumar of Mizuho. Your line is now open.

Hi, Good morning, guys and thanks for taking my question.

I want to start on slide 11 that you've been espousing the co development.

Coach for some time and you show please.

The solid results and consistent results since 2020.

Just curious one of your I guess your peers in the basin talked about increasing recoveries by 20%.

Through the use of technology.

You guys are at the cutting edge yourself. So I'm curious are you seeing anything out there that can improve recovery factors by <unk>.

That kind of magnitude.

Listen we keep our finger on the pulse of a lot of emerging technologies.

We focus on.

Internal expertise on improving our recovery.

<unk>.

Thats not something Thats on our radar screen that we're aware of today, but that's not to say that the potential is not there as you look forward in the future.

There's a lot of smart guys in our industry.

We have a ton of smart guys inside diamondback, and whether that technologies developed internally or externally it's widely communicated.

Quickly followed.

Particularly that kind of result, so.

We're focused on improving recovery and I know our peers are doing the same.

That's not a today number for sure though.

Okay. I guess my follow up would be if you are a force Pos follower.

You've talked about how volume is an output of your.

Program your capital allocation framework.

In an event that you could improve recoveries that way would you allow would you keep activity flat or do you expect to reduce capex and just maintain that volume growth to be low single digits.

Yes.

I think generally that would be a great problem to have.

It really ties to this.

Can you run a simultaneous program consistently on that position in those projects and those pads and kind of all goes back to this longer cycle nature of of.

Of the shale business model.

I think we feel really good about for example, frac crews running consistently right now and then.

The infrastructure to do that.

If growth exceeded expectations that there'll be a good problem to have.

Great. Thanks, that's it from me guys.

Alright, thank you.

One moment for our next question.

The next question comes from the line of Charles Meade Johnson Rice. Your line is now open.

Good morning, <unk> and Danny I wanted to ask one more question maybe from a different angle on the on the A&D outlook case, I think I think he was.

I think I wrote down what you said that you are.

Prepare comments or maybe earlier Q&A that theres very few very few positions out there.

<unk> NV and so that makes sense that you guys. Your bar is high.

But from my seat. It also looks like if you look at the other side of the question is it looks like.

There is there's not a lot of positions you want to buy but theres also.

Fewer possible fewer potential buyers out there, particularly for some of the.

Some of these large.

Large private position. So so how do how does the I guess do you agree that theres fewer credible buyers for some of these big packages that may still be out there.

And more broadly how was the.

How should we kind of the lineup shifting as youre active in data rooms and in processes.

Buyers versus sellers.

Yes, that's an interesting observation Charles.

Not lost on us.

You've got you've got a couple of very large buyers do do a couple of deals in the in the basin and out of the basin.

It kind of do whatever they want it seems like but.

I would just say generally industry consolidation has happened is continuing to happen.

I think a lot of the privates are Don as you mentioned.

A logical acquirers.

I would just say that there is there may be less buyers of assets, but they are all very well funded.

Good operators big balance sheets.

And competitive so I think we just have to stick to our guns and our underwriting philosophy, which is our cost structure our rates of return internally our hurdles for commodity price and usually that has resulted in more assets.

Coming to Diamondback, because you can underwrite.

Wells drilled at one or $2 million cheaper, we can run above cheaper and thats the kind of stuff that they are accretive to our shareholders.

Got it thanks for that that's it for me.

Thanks, Charles Thanks Charles.

Thank you one moment for our next question.

Our next question comes from the line of Arun <unk> of Jpmorgan Securities. Your line is now open.

Yes, good morning, gentlemen, I wanted to keep on the A&D theme.

When we are assessing the potential of a large private or one of these unicorns.

Silly.

Consolidate.

Does it just come back to price or is there something do you think that they think about in terms of the independent versus major oil business model that could be advantageous to us to accompany with like Diamondback who's in Midland and again one of the.

The lowest cost structures in the industry.

Yes, Arun, we don't spend a lot of time thinking about what what sellers.

Think about what is the best opportunity available for our shareholders and creating shareholder value for our shareholders and.

At the end of the day.

Diamondback.

Hand on heart is one of the best positions remaining in North America.

The best cost structure and that should be a a very winning combination for our shareholders for a long time here.

Understood.

I wanted to maybe switch gears and just talk about the DNC.

Efficiency gains.

Yeah.

Really surprised to see.

This year.

The drilling efficiency gain it seems like the drilling efficiency gains are outpacing maybe what we're seeing on the completion side.

Or are you guys recalibrating.

The cult the rig to Frac crew ratio, but give us a sense of.

Maybe what your what Youre doing on the drilling side for these efficiency gains and maybe help us recalibrate, what that drilling to simulcast crew ratio it looks like today.

Yeah. It's interesting we really haven't thought about the rig crew ratio in a long time, because it's just changed so much I think we've moved to a world where we know how many wells, we need to drill and how many wells we need to complete in a year.

Numbers.

And the drilling side, maybe a year ago that was 15% or 16 rigs for a full year and now this year and upcoming it looks more like 14% to 15. So the amount of work that our planning team does on on the plan and how we're doing relative to plan.

It's pretty astounding and how far ahead. They are on these pads and when we need to pick up a rig and when we need to drop it really kind of just targeting can we keep those sino frac crews busy consistently.

I guess you know I guess the number is kind of in that high threes almost four rigs to one time will frac crew today.

Yes.

And I think that.

<unk>.

My case that our goal is to keep the drilling program ahead of this novel correctly.

And just keep the final frac fleets moving inefficient just like we want to keep rigs moving from pad to pad without waiting on Pac instruction or whatever so we kind of see them as two different.

Programs altogether, knowing that they're very dependent on each other but.

I think the drilling and completion teams. Both this year have really done an excellent job of leaning in and and.

No.

Pushing the machine to the limits and finding the little pieces of efficiency gains that can pick up and we continue as we've always done to tinker and find better ways to.

To execute our development strategy and build a better mouse trap.

When we find.

Different ways to design these wells and execute that we will lean into it and continue to chase that.

The efficiency line.

Great. Thanks, a lot.

Thanks, Ron Thanks, Eric.

Alright. Thank you one moment for our next question.

Okay.

The next question comes from the line of Scott Gruber of Citigroup. Your line is now open.

Yes, good morning, and congrats on another good quarter.

I want to follow up on that.

Right.

I want to follow up on the routes question just.

Just on the activity set into next year.

And get some more clarity on the plan for the docs. So it sounds like it could be running.

The 14 or 15 rigs.

Kim will you end up drilling 330, or so wells.

By running 14, or 15 rigs or what are the base plan for next year contemplate a drawdown of some of those excess stocks.

I don't think we're planning on drawing any down you know absent absent any in the field issues I think generally we feel a lot better at this level of docs for the size of projects that we have ahead of us.

Earlier this year, we were getting pretty close.

The rigs and the Frac crews, we're getting pretty close to the rigs getting off location.

A 20, well pad are 24, well pad or however, you want to break it up.

You have to have all 24 wells done before you can bring on the drilling side, where you can bring the frac crew in or at least that's how we do it and.

That's why that kind of $1 50 number we mentioned feels like a much more balanced number going forward.

I got you so the inventory count.

Under normal conditions, and just going up.

Got it just feels like a good good inventory number again going back we're not these.

Today's of.

Two well pads, where if something bad happens you can pull on the pad and go somewhere else.

These are long cycle, many Danny let's call them, many offshore projects given the amount of dollars that go into a project before first oil comes online.

That makes sense.

Hey, good detail on.

The cost trends across the various.

Buckets on slide 10.

Yes, you broke up.

You know going through RFP season for.

There are various services I know you've got some longer term contracts in place but do.

Do you think you'll you'll see any continued deflation across any of the major buckets as you go into 'twenty, four or they're starting to stabilize now.

Yeah, I think we think it's kind of stabilizing right now.

And for US there really is no RFP season, right RP seasons everyday Diamondback, if some things cheaper than we can do something cheaper or replace something with something cheaper. It is going to happen right away, it's not going away.

For next season or for the summer, it's going to happen now so it's a constant RFP season here and these are all real time cost of it.

The team has to present to Travis.

On a line by line basis every quarter end.

This is a real time look at where we are and where things are headed you noticed we've put our Q4 2023 number in there just to kind of show where even we've moved from Q3 to Q4.

Got it appreciate the color. Thank you.

Thanks Scott.

Thank you one moment for our next question.

Okay.

Our next question comes from the line of Leo Mariani of Roth <unk>. Your line is now open.

Okay.

I just wanted to follow up a little bit on 2024, I'm kind of reading this right. It looks like you guys are talking about.

Rob budget next year, just a hair over two and a half.

It sounds like Thats kind of flat activity just wanted to get a sense of kind of what's assumed in there for inflation or deflation are you just kind of assuming sort of current.

Well costs in that number.

Yes.

Kind of a little conservative here Leo So I would say, we're kind of in the range of where we think we are today. You know again, we think generally service costs have kind of bottomed or flattened out and.

Absent a major change in rig count this feels like a pretty good.

It's a pretty good range for.

For next year.

Okay.

And then just to follow up quickly on the M&A topic here.

Thank you guys have made it pretty clear that you want to continue to be a consolidator over time with your cost advantage I guess at the same time, just kind of I know you guys talk about kind of a $60 type of budgeting case for oil obviously been above there is there any scenario where thanks.

<unk> thinks about potentially going other way and actually selling at the end of the day.

You know <unk> tried to address that a little bit in my opening comments I was one of the first questions and also.

And I'll, let her look we'll always do the right thing for our shareholders. We've been I feel like we've done that for 12 years now.

But again, what our focus is on.

Delivering our business plan and we believe in our business model, we believe that there's a meaningful spot and our investment community for a company like Diamondback and we continued to execute flawlessly and I think I think I'm really really confident about what our forward plan looks like.

Okay. Thanks.

Thanks Leah.

Alright, Thank you and one moment for our next question.

Yeah.

Next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Alright, Thank you good morning.

Two questions from one.

One of the weight that to reduce cost I think the industry is smoothing for transportation.

And shop at that wondering if you can give us some idea that how far along on your process.

Doing so.

And secondly that with the deep <unk>.

I think in the past that you guys.

It's a very powerful one thing infrastructure and all of that so is that signaling that now you have a change of view.

What kind of infrastructure and need to be on a buy or need to be control.

Diamond Bank going forward. So should we just assume that this means that you really don't think that.

The necessary for you to have control on two one dose infrastructure. Thank you.

Yes, good question, Paul I'll take the second one first.

Midstream infrastructure.

We spent a lot of money building those systems to the specs that we needed and so I think we're not.

Turning over a blank canvas right. This is a painting that's already been.

It's finished finishing touches and so we feel confident particularly with a lot of our field team members going over to deep blue to run the asset.

That will be well well served as its largest customer and also a large equity holders. So I think if we are early in our development plan might be a different story.

But in this case, it's a very well built out system that that is kind of ready made to turn it over to them too and our mines do some more things commercially that we couldnt do.

As a standalone water enterprise and then your other question I'll, let deprecation.

A hot topic in the Permian.

I think generally electrification means both lower cost and lower environmental footprint and that's a great thing for us in this basin.

We've done a lot of work ourselves I think the state of Texas.

And the utilities need to kind of do their part to get more power out to the Permian to connect to all of us. So that we can run off line power versus.

Different forms of generation in the field. So I think that's going to be a constant.

Constant battle that we are intently focused on and.

Again, it saves us money and improves environmental performance that feels like a win.

Just curious that I mean, what percent of your operation now that's already been buying that where you think the biggest opportunity over the next one or two years.

Yes.

We've got about 90% to 95% of our current production operations electrified.

Ben the biggest opportunities we've been working on to date.

The production operations world or been in electrification of our compression fleet and I think we're probably 70 ish percent electrified there. So we'll continue to work on getting rid of our gas.

Gastroparesis compressors and putting electric packages in their place.

And then on the D&C side.

We've got to see.

Final Frac fleets that are halliburton, what they call their Zeus fleets, which are their electric fleets.

We've really enjoyed the benefits of those and look forward to continuing to trying to electrify the completion world and then on the drilling side.

God, I think five or six rigs running right now on online power.

And we're continuing to.

Put in the infrastructure that we need to to run those rigs offline power.

As the supply chain kind of frees up.

The back of Covid, and we can get the electrical equipment, we need.

To convert those rigs so it's.

Kind of all over.

But but we're we're.

We're working on it as fast as we can and.

I anticipate that over the next four five years, there won't be much of the field thats not electrified.

Thank you.

Alright. Thank you. This does conclude the question and answer session.

I would now like to turn it back to Travis Stice, Chairman and CEO for closing remarks.

I appreciate all the good questions. This morning I hope.

Our shareholder letter constructed and the way that we can help communicate details about our business plan. The last comment I want to make before we sign off is that we have an opportunity. This saturday to recognize all of our veterans across this country.

Headroom today, certainly for all of the veterans that are important about diamondback. Thank you for your service and then anyone that's on the phone, but also dedicated a portion of their lives to.

So our country I wanted to tell you. Thank you for your service as well and then particularly for the Diamondback employees hopefully, we'll see you at at breakfast or lunch ceremonies that we would have planned for this Friday. So thank you all have a great day and God bless.

Alright. Thank you for your participation in today's conference. This does conclude the program you may now disconnect.

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Good day, and thank you for standing by.

Come to the Diamondback energy third quarter 2023 earnings conference call.

At this time all participants are in a listen only mode.

To withdraw your question. Please press star one again.

Please be advised that today's conference is being recorded.

I would now like to hand, the conference over to your first speaker today, Adam Lawlis VP of Investor Relations. Please go ahead.

Representing Diamondback today are Travis Stice, Chairman and CEO case fans Hoff, President and CFO and Danny Wilson 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.

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.

Additionally, we'll 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 will now turn the call over to Travis Stice.

Thank you Adam and good morning to everyone as Adam mentioned, we released the shareholder letter last night that contains much of the narrative. We hope to cover again. This morning, so with that we'll just open the lines up for questions operator.

To withdraw your question. Please press star one again.

Please standby, while we compile the Q&A roster.

Our first question comes from the line of Neal Dingmann of <unk> Securities. Please go ahead.

Good morning, Travis and team thanks for the time and another nice quarter try. That's my first question is on capital allocation specifically.

Several quarters ago. You suggested you all would return to more of a production growth type model I would call. It and I think you've mentioned when the macro fundamentals supported I'm. Just wondering do you believe we're close to that scenario and wondering why do you believe that.

The continued high free cash flow payout is warranted.

Yes, Neil that's a good question look the world is certainly in a in a mess right now across any number of fronts.

All of which could potentially move to markets, both positively and negatively negatively both with a supply disruption or even a demand destruction as well too.

Obviously, we can't control any of those items again, we simply respond to our shareholders that own our company that right now no return to shareholder model versus a growth model as we've estimated our plans as we look forward into next year.

Again look for real efficient capital allocation and as an output of that capital allocation. We expect low single digit type volume growth again, not as an input, but what results from an efficient capital allocation program.

Got it that makes sense in this environment and then secondly on your development Couldnt help but notice the new slides on slides 10, and 11 highlighted the efficient execution and then differentiated development. My question is does most of your remaining Midland inventory led to the 24 average wells.

Wells per project size that you mentioned and then I'm just wondering could you speak to where the largest cost efficiencies continue to come from on these projects.

Sure on the development strategy overtime slide which is slide 11 for those of you that are looking at it online we tried to demonstrate.

Our evolution from 2015 to today, and we said average wells per project is about 24 wells.

Generally that applies across our Midland basin, however, not all.

Posits are equal.

Terms of the way the shales were laid down across the Midland basin. So there will be areas, where we can do slightly more than 24 wells.

And then there is also will be slightly less than 24 wells, which usually translates to one or two wells less per shale intervals. So again, it's a general representation showing.

The development over time, but thats a good thats a good summary.

Yes.

What was your second question, Jason on the cost on the cost or cadence and I talked about I mean is it just on.

I know you have lower KC, and just different sort of raw material costs, but is there is there other areas in that larger projects that are causing these.

When you see that well productivity chart on the right.

Sort of what's driving the lower cost efficiencies there.

It's really as you look into it looking into next year.

We feel more of a kind of a steady state run rate on our cost there'll be some puts and takes on both sides of the equation take Q&A, but I think the biggest benefit to these large scale development Neal is.

The consistency of running the rigs and the <unk>.

Same spot for a longer period of time, but on the Frac size, where we saved the most money from a capital efficiency perspective, because we're doing some cases two simultaneous crews on the same site at the same time, so year saving essentially 250 to $300000 of wells from simulcast <unk> and now we add two of those.

As fleets are E fleets that runoff lean gas and save kind of another 200 $250000 a while so this large scale development kind of ties to the longer cycle nature of our business and that also means we don't want to change the plan.

Every move in oil price and so we've.

<unk> had a consistent plan here for a few years now and the output of that is consistent results on the on the well.

And the well productivity per foot.

Thank you both.

Thanks Neil.

Thank you one moment for our next question.

Our next question comes from the line of Neil Mehta of Goldman Sachs <unk> Company. Your line is open.

Yes.

Thanks, guys.

Appreciate the helpful letter and the time today.

Perhaps when we start on return of capital or the topic to talk about this later.

Wanted to err on the side of caution as it relates to.

Buying back stock to avoid pre purchasing pretty quickly and as a result leaned into the variable dividend in the last quarter can you talk about.

The way that Youre approaching this and how that Chad.

For them the way, we think about the split between buybacks and dividends going forward.

Sure.

Main focus remains.

Sustainable and growing base dividend that we think represents the most.

Making our shareholders hold in the form of variable, which we've seen.

Where our stock is trading relative to that calculation, we either buy more of further.

Further dislocation, we get from that we buy.

We increase or.

If not then we pivoted to.

To share repurchase.

Variable dividend like we did this time around so.

Again.

It's base dividend and share repurchases.

With a degree of caution in our pro cyclical environment, and then honoring our commitment through the form of a variable dividend.

Okay. That's really helpful and the follow up is just on noncore asset sales we've done a good job of exceeding your target can you talk a little bit about that.

The deep Blue Midland Basin, JV, and then not only in terms of the proceeds but what does it mean for your go forward cost structure.

As we think about modeling the impacts through 2024.

Yes. Good question Neil the deeper JV was a very big deal for US. If you know it took a long time to to pull together, we have built a significant amount of midstream infrastructure over the years and spent a lot of capital doing yet and we felt it was an opportune time to monetize that in the hands of <unk>.

We see his operational expertise and deep blue in the five <unk> I think they have already proven to have commercial success with third parties, where.

Maybe if you haven't gone into that business card you weren't going to have the same type of commercial success.

I think.

That sector is certainly ripe for consolidation as well and I think they are the experts that can get that guidance. So that's kind of why we retained the 30% equity interest in the business, we're very confident that they're going to be able to grow the business and generate a good return for our shareholders.

Outside of the $500 million proceeds we got in which is the big the big Big winner there will be some impact to our cost structure I would say generally.

LOE is going to be up about 8% to 10% versus prior as a company and then.

We will have a lot less midstream capex is we don't have very many operated midstream assets and that'll be kind of canceled out by <unk>.

Thanks, Tim.

Thanks Neil.

Great. Thank you one moment for our next question.

Our next question comes from the line of David tackle bomb of TD Cowen. Your line is now open.

Okay.

Good morning, Travis and case team Danny Thanks for taking my questions.

Travis I was curious if you could talk a little bit more.

About the remarks in the shareholder letter on being an acquirer next quarter.

And just maybe putting in context sort of.

How robust do you think that opportunity set is right now just given the cycles in the business and some of the cycles that have gone through the Permian right now.

Yes, David and I appreciate you're referencing the shareholder letter I tried to address that head on and I think just in a more macro sense, we'll always do what's right for our shareholders and when we've got now over over a decade of what I think is demonstrated and doing the right thing for our shareholders, but we remain laser focused on.

Delivering on our business plan and you are right. We have built this company through <unk>.

<unk> explored strategy.

But I think as investors really started to understand we have such a high quality inventory right now that the bar is pretty high for additional opportunities to add too.

Add to our inventory that meets those.

There has been a lot of private equity roll through and and I think.

Based on based on lack of our name on those it just tells you where we view those assets relative to our inventory like Ikea like I said I'm really pleased with the quality of our inventory and I think.

I think we're executing on that in a flawless manner.

I appreciate that.

Maybe just for case.

The DUC backlog is built I guess up to a 150 by the end of the year I think you guys talked about.

Low single digit organic oil growth for next year.

One I just wanted to confirm that.

Oil growth is reflecting that benefit.

The increase royalty interest through the Bantam acquisition or Viper acquisition rather.

That's.

How we should be thinking about that growth rate and then just in concert with the DUC backlog.

Or is it should we think about that flexibility, especially in this pricing environment just based on Frac crew availability or is that really just like a capital allocation decision.

Yes.

It looks like organic growth comment first certainly.

Excluding the LIFO deal, we expect it to grow organically.

We expect to grow organically in 2024, I think the Viper deal provides a little bit of a jump start here in Q4, but I think the team is expecting to grow off that number.

At a steady state throughout the next year.

Just due to the quality of what we've got in front of us on the DUC side, we were kind of operating pretty close to the rigs on the completion crews.

I really needed some.

Some flexibility here in the drilling team has done a really good job. This year getting ahead of plan drilling more wells than expected sooner.

But these are these large pads in large projects you really want to have the flexibility to be able to go somewhere if something.

Something bad happens and DUC backlog allows that so I think $1 50, plus or minus 10 or 20 wells.

Either way is a pretty good number for our run rate and we've kind of set that set the stage for a world where rerun.

Four of these simultaneous cruise consistently throughout the year the age do about 80 wells a year and in our mind, that's kind of the most capital efficient development plan. We can we can imagine here. So that's our backlog just less any sleep a little better at night.

It allows for some flexibility heading into next year.

Okay, Neil Thanks for the responses.

Thanks, David.

Alright. Thank you one moment for our next question.

The next question comes from the line of Scott Hanold of RBC capital markets. Your line is now open.

Yes. Thanks.

If I could.

Go back to the M&A topic, a little bit differently.

<unk>.

Keith Travis when you step back and think about like where <unk> inventory depth is and to be a long term successful large scale play in the Midland.

Do you think that more large scale M&A is necessary over time, and just remind us where you think your inventory life is and where ideally would you like it to be.

Yes, I mean, I don't think its necessary Scott I think we've positioned the business.

Through both large scale and small scale M&A, just kind of been in our DNA for the last 10 years.

I kind of go back to thinking about what positions in North American shale or in the Midland Basin with Dnb and there are very few particularly with where we sit today and the amount of deals we've done over the years. So I think it's I think it is.

Fortunate spot to begin with the inventory duration and depth that we have relative to whats out there I just think <unk> comment is.

Really about knowing who you are and this company has been a acquire and exploit company that's been able to execute on acquiring and exploiting assets through our low cost structure.

Generally we are not a philosophy that the low cost operator in a commodity based business wins and.

Our cost structure is what has created.

This business to be as big as it is today Charles anything to that.

Makes sense.

Talked about the high bar for entry into.

We ended the diamondback portfolio.

Flawless execution from our teams and converting rock into cash flow and Thats.

Cost structures enviable.

Our execution prowess is unmatched.

That makes that makes a big difference when you talk about a profitable oil and gas company like Arizona.

Yeah, and then just and just as part of that was the inventory life kind of conversation more of like where you think youre at now and where do you think is ideal.

Yes, I mean I think.

I kind of said this.

And we can put our next five years up with anybody and in North America, I still stand by that I.

I think we have another solid five or 10 years beyond that it's very logical that at all.

Some point youre going to have to move down the quality of inventory.

We don't see that in the floor plan today, but if we retain our cost structure and our ability to drill wells, one or $152 million cheaper well as the shale cost curve goes up we continue to stay at the low end of that cost curve.

Our mantra for 10 years now we started with <unk>.

<unk> thousand acres, an hour at $5 50 and.

That culture, and mantra has not changed and I think that sets us up well for a world.

Where assets are getting more more and more sparse.

Got it understood and if I could follow up on.

Our conversation we had last night just on the shareholder returns.

Stock buybacks and I thought it was an interesting conversation we had on just where things intrinsic value is now and the opportunity to grow that over time.

So like when you step back and think about the current oil market. Obviously, we're in a little bit more heightened oil price versus your intrinsic point Budd Lake as you see yourself progressing over the next years.

Does it seem to make sense that buying it buying back stock at higher prices in this heightened market relative to what you did in the past still make sense from a value return standpoint.

Yes, it's really all about all about value and I think we talked about last night. If you run your business conservatively from an oil price perspective, and accrete value quarterly.

At 75 to 80 to $85 crude.

Youre actually building equity value.

On a conservative basis, right I kind of said last night to you that.

Travis mentioned, we want to be conservative on buying back stock, we think capital is precious and capital discipline not just supplies in the field that it applies.

So returning capital to shareholders and that's why we've had this flexible returning capital program since we put it in place two five years ago.

Thank you.

Thanks Scott.

Alright. Thank you for your question one moment for our next.

Our next question comes from the line of Roger read of Wells Fargo Securities. Your line is now open.

Yes, thanks, good morning.

I think I'll skip the obligatory share repo versus variable dividend question for a moment and just.

<unk> that we're not going to have some of the asset sales that have been going on and that has certainly helped on the sort of cash flow generation assets.

Yes, that's a good question Roger.

It's interesting.

Slide in slide 10 about operational track record and prowess.

I think we've sat with sat in this room, two or three years ago, saying, hey, the drilling guys there.

Here the asymptotic curve of drilling these wells well if you look at the top left of that chart Theres still taking days out of the average well on a much bigger program you guys are drilling 280 wells in the Midland Basin.

Two to three or four days faster than they were even two years ago.

The culture that we built accrete that value to our shareholders and thats something remodel, but it certainly comes our way so in the field I think thats part of what is coming our way.

I also think.

Generally we've tested some other zones in the Midland Basin that look very very good we've got a couple of upper stream any tests in the northern Midland Basin that look very good relative to our metal spread rate Jo mill developments and we're excited about that but I think the Wolfcamp D and the Midland Basin is starting to become a prime.

Barry Development zone, and some of the basin and certainly there is a lot of excitement about deeper zones.

In the Midland Basin, as well as the Barnett and Woodford that were.

<unk> testing, so I think the Midland basin, the stack pay and the amount of oil in place just just provides a lot of opportunity for.

Future value.

To increase our shareholders that they don't know about today Travis you want add anything to that Roger.

<unk> 10 years ago. When we first started this research we're still drilling with.

Vertical wells and I'll.

Put in the letter that we released last night, just a couple of data points on a 7500 foot lateral well, which has a total depth of total membership of about what we were drilling vertically when we started but drilling.

We drilled those 7500 foot lateral wells in under four days and when we started we were drilling it sometimes it take us over 'twenty four 'twenty five days to get down to that same measured depth vertically and so.

Probably the most repeated question that we get.

Is what is the secret sauce, what is the magic that Diamondback does that allows execution quarter over quarter to just far exceed the competition.

It's essentially the same rock and the same tools, but the culture that we've built here at this company with that laser focus on the conversion process of rock into cash flow.

Felt by every employee in the company and when you have everyone's leaning in the same direction on cost and efficiency.

As long as we can continue to give them a good rock theyre going to we're going to generate the outstanding results that we're known for so I know thats, a little bit of motherhood, and Apple pie, but I'm really proud of the organization for.

Through all the cycles, we've been through over the last 10 years, what Hasnt changed is an unrelenting focus on delivering.

Best in class execution highest margin barrels at the lowest cost.

I appreciate that I'm, not going to be down between motherhood and Apple pie here in the U S. So I'll turn it back thanks.

Thanks Roger.

Thank you one moment for our next question.

Alright. Our next question comes from the line of Derrick Whitfield of Stifel. Please go ahead.

Good morning, all and thanks for all the incremental disclosures this quarter.

Thanks Derek.

Building on an earlier question, how should we think about 2020 for maintenance capital run rate, assuming the benefit of deflation and your current operational efficiencies.

That's a good question Derek.

Probably say that maintenance capex would be $1 million to $200 million cheaper.

30 Wells Navy, Danny Yes, I think we're kind of looking at it.

Maintenance, Okay. Our case for 2024 is kind of a maintenance activity case of flat activity, our folks a little bit of a growth but.

If we were to try and maintain a flat production profile you'd probably be in the line of 20 to 30 less wells in the year.

While you're on that topic of maintenance Capex I might just point you to slide seven we've had that slide and there are a couple of times, but it shows maintenance Capex, which David just defined as kind of holding.

Fourth quarter production flat for next year and I just want to show you what our breakeven prices are on that slide $32, a barrel that cover maintenance cap maintenance capex.

$40 a barrel to cover our base dividend. So that's kind of goes back to my cost of execution comments that ultimately translate into a very protected business model, even though at low commodity prices.

That's great and as my follow up with respect to the noncore asset sales.

How should we think about the market value of whats being retained by Diamondback and how that will be realized over time now that you've exceeded your disposal target.

Yes. Good question, Derek we did lay out some of our remaining JV that we have on slide 26.

Yes, I think some of those largely or monetize at some point in the coming years.

We are in a huge rush to do so but in.

In most cases, we're kind of.

Non op partner to these JV that that do have a ton of value just not something that we can.

Commit to.

Monetizing today.

Well done guys. Thanks for your time.

Thanks Derek.

Alright. Thank you one moment for our next question.

Our next question comes from the line of Kevin Mccurdy Pickering Energy Partners. Your line is now open.

Hey, good morning.

I appreciate the commentary on industry consolidation digging into your cost structure comments, a little bit now that you have had higher burden lario and houseware unless a year can you comment on the level of cost synergies you've created in those transactions or maybe just share with us your analysis, the diamond backs costs versus peers I'm, just trying to get a sense of what kind of uplift assets gateway.

They are incorporated into diamondback in your cost structure.

Yes.

Good question Kevin.

I think some malaria.

<unk> costs were near 885, $9 5 million for a 10000 foot lateral near drilling on the <unk>.

Six five to seven.

So that's kind of been our mantra for a long time.

I'll just say generally if you spoke a few deals up <unk> was a.

And execution deal because we knew we could we could drill those units cheaper and execute on.

Large scale development.

Say firebird is more of a technical deal and.

We had a technical view of that particular area that the basin could move further west.

In the northern part portion there'd be some multi zone development that looks really good I think we were conservative on the multi zone potential of the central block and now feel a little more confident about the wolfcamp, a and a lower sprayberry and maybe being wine racked in that area and also with the benefit of that block being so.

So contiguous we're able to.

Bring a 15000 foot lateral manufacturing process to that area. So we underwrite these deals that are in our cost structure.

Which if you look at our cost structure versus others that means we should get.

More of those properties at the same rate of return because of our ability to execute.

Great. That's that's the only one for me I appreciate taking my question.

Good question Kevin.

Thank you one moment for our next question.

Our next question comes from the line of Jeffrey <unk> of Tpa <unk> Company. Your line is now open.

Good morning, everyone and thanks for taking my questions.

Thanks first one is on the thoughts on capital allocation side. If you can just speak to any more detail on next year's plan in terms of where you might focus within the Midland basin. Both in terms of geography, but also maybe just less active zone in terms of industry activity that you may be testing more and if you could speak maybe a bit more onto some of that lateral length commentary in terms of how.

It might evolve over the near term program that would be helpful as well.

Yes, Jeff with these with these longer cycle projects, we have a pretty good view of what the projects look like coming up here in 2024.

I would say generally.

To be in the range of 11000 feet average lateral lengths, probably maybe even a little bit more than that.

I would say, it's also a very heavy.

Martin County development year for US, which is which is great in a large large scale multiyear multi zone development in some of the <unk>.

Best undeveloped resource remaining in the Midland Basin I'd.

I'd say from a from a testing perspective, some of some more wolfcamp b, probably making it into the plan and a lot more upper sprayberry.

Into the plan, we kind of have a couple of really good tests in no part of our culture is when something works, we implemented very very quickly and that's how we kind of see the shallower development picking up the pace in the northern Midland Basin, particularly that northwest Martin County area that we see.

Feel really good about for adding a new zone.

Okay, Great and then maybe just a housekeeping type question on the noncore asset sales side, particularly on the upstream.

People know to now just how you're exceeding or you've already exceeded the target before year end here and it makes sense. There is no need to go out and do more right away, but just wondering if you can speak to potential opportunities maybe in terms of longer dated inventory that someone else might find more valuable and de risk that when you think about the opportunity set from here.

Yes, good question that ties to some of that didn't answering your last question.

The number of wells in the Midland Basin will be.

85%, 90% of the total capital to the Delaware Basin still be a small percentage of total capital I think I'm getting what your question is where does the Delaware basin sit in the portfolio and I think I think for US certainly we start that area of capital a little bit here in the last few years.

I think it provides a lot of cash flow and a lot of production, which is beneficial to us today.

As you've seen over the course of the year and it certainly seems like inventory is coming at a premium and there may come a time, where someone really really wants that delaware position of ours or portions of it but we're not going to sell it for.

A song at PV 15, right PDP so.

I think we're going to hold it for now and if someone wants to pay for upside and unreasonable.

Number versus where we trade, we'll take a look at it.

Perfect. Thank you.

Thanks Chip.

Thank you one moment for our next question.

Our next question comes from the line of <unk> Kumar of Mizuho. Your line is now open.

Hi, Good morning, guys and thanks for taking my question.

To start on slide 11, you've been espousing the co development.

Approach for some time and you show please.

The solid results and consistent results since 2020.

Just curious one of your I guess peers.

Peers in the basin talked about increasing recoveries by 20%.

Through the use of technology.

You guys are at the cutting edge yourself. So im curious are you seeing anything out there that can improve recovery factors.

By that kind of magnitude.

We keep our finger on the pulse of a lot of emerging technologies.

We focus on.

Our internal expertise on improving our recovery.

Thats not something Thats on our radar screen that we're aware of today, but that's not to say that the potential is not there as you look forward in the future.

There's a lot of smart guys in our industry.

We have a ton of smart guys inside diamondback, and whether that technologies developed internally or externally. It's widely communicated and quickly followed his particular of that kind of result, so.

We're focused on improving recovery and I know our peers are doing the same.

That's not a today number for sure though.

Okay. I guess my follow up would be if you are a force fast follower.

You've talked about how volume is an output of your.

Program your capital allocation framework.

In an event that you could improve recoveries that way would you allow would you keep activity flat or would you expect to reduce capex and just maintain that volume growth to be low single digits.

Yes.

I think generally that would be a great problem to have.

It really ties to this.

Can you run the Sinopec program consistently on that position in those projects and those pads kind of all goes back to this longer cycle nature of.

Of the shale business model.

I think we feel really good about for example, frac crews running consistently right now and then.

The infrastructure to do that.

If growth exceeded expectations.

A good problem to have.

Great. Thanks, that's it from me guys.

Alright, thank you.

One moment for our next question.

The next question comes from the line of Charles Meade with Johnson Rice. Your line is now open.

Good morning, <unk> and Danny I wanted to ask one more question maybe from a different angle on the on the A&D outlook case that I think I think he was.

I think I wrote down what you said that.

Your prepared comments or maybe earlier Q&A that theres very few very few positions out there.

That you envy and so that makes sense that you guys. Your bar is high.

But from my seat. It also looks like if you look at the other side of the question it looks like.

Theres not a lot of positions you're going to buy but theres also.

Fewer possible fewer potential buyers out there, particularly for some of the.

Some of these large.

Large private position. So so how do how does the I guess do you agree that theres fewer credible buyers for some of these big packages that may still be out there.

And more broadly how was the how is the kind of the lineup shifting as youre active in data rooms and in processes.

Buyers versus sellers.

Yes, it's an interesting observation Charles certainly not lost on us.

You've got you've got a couple of very large buyers do do a couple of deals in the in the basin and out of the basin, making.

They can kind of do whatever they want it seems like but.

I would just say generally industry consolidation has happened is continuing to happen.

I think a lot of the privates are Don as you mentioned.

It's a logical acquirers.

I'll just say that there is there may be less buyers of assets, but they are all very well funded.

Good operators big balance sheets.

Coming to Diamondback, because you can underwrite.

Wells drilled at one or $2 million cheaper, we can run above cheaper and thats the kind of stuff that they are accretive to our shareholders.

Got it thanks for that that's it for me.

Thanks, Charles Thanks Charles.

Thank you one moment for our next question.

Our next question comes from the line of Arun <unk> of Jpmorgan Securities. Your line is now open.

Yes, good morning, gentlemen, I wanted to keep on the A&D theme.

When we are assessing the potential of a large private or one of these unicorns to potentially.

Consolidate.

The lowest cost structures in the industry.

Yes, Arun we don't.

We spent a lot of time thinking about what what solid state. We just think about what is the best opportunity available for our shareholders and creating shareholder value for our shareholders and.

At the end of the day.

I think diamondback hand on heart is one of the best positions remaining in North America, and the best cost structure and that should be a a very winning combination for our shareholders for a long time here.

Understood.

I wanted to maybe switch gears and just talk about the DNC.

Efficiency gains.

Yeah.

Really surprised to see.

This year.

The drilling efficiency gain it seems like the drilling efficiency gains are outpacing maybe what we're seeing on the completion side.

Are you guys recalibrating.

Culp the rig the Frac crew ratio, but give us a sense of.

Maybe what your what Youre doing on the drilling side for these efficiency gains and maybe help us recalibrate what that drilling this time will frac crew ratio it looks like today.

Yes, it's interesting we really haven't thought about the rig the crew ratio in a long time, because it's just changed so much I think we've moved to a world where we know how many wells, we need to drill and how many wells we need to complete in a year it hit hit numbers.

The drilling side, maybe a year ago that was 15% to 16 rigs for a full year and now this year and upcoming it looks more like 14% to 15. So the amount of work that our planning team does on on the plan and how we're doing relative to plan is pretty astounding and how far ahead.

They are on these pads and when we need to pick up a rig and when we need to drop it really kind of just targeting can we keep those frac crews busy consistently.

I would guess I guess the numbers kind of in that high threes, almost four rigs to one time will frac crew today.

Yes.

And I think.

That.

My case that our goal is to keep the drilling program ahead of this animal correctly and.

And just keep the final frac fleets moving inefficient just like we want to keep rigs moving from pad to pad without waiting on Pac instruction or whatever so we kind of see them as two different.

Programs altogether, knowing that they are very dependent on each other but.

I think the drilling and completion teams. Both this year have really done an excellent job of leaning in and.

Pushing the machine to the limits and finding the little pieces of efficiency gains that can pick up and we continue as we've always done to tinker and find better ways to.

The execute our development strategy and build a better mousetrap.

Fine.

Different ways to design these wells and execute that we will lean into it and continue to chase that.

The efficiency line.

Okay.

Alright, Thanks, a lot.

Thank you and thanks for.

Alright. Thank you one moment for our next question.

Okay.

The next question comes from the line of Scott Gruber of Citigroup. Your line is now open.

Yes, good morning, and congrats on another good quarter.

I want to follow up on them.

Thanks.

I want to follow up on <unk> question.

Just on the activity set into next year.

You get some more clarity on the plan for the ducks, so it sounds like it could be running.

The 14 or 15 rigs.

Ken will you end up drilling 330, or so wells.

By running 14, or 15 rigs or what are the base plan for next year contemplate a drawdown of some of those excess ducks.

I don't think we're planning on drawing any down absent absent any in the field issues I think generally we feel a lot better at this level of docs for the size of projects that we have ahead of us.

Earlier this year, we were getting pretty close.

The rates of the factories, we're getting pretty close to the right getting off location.

A 20, well pad are 24, well pad or however, you want to break it up.

You have to have all 24 wells done before you can bring on the drilling side, where you can bring the frac crew in or at least that's how we do it and.

That's why that kind of $1 50 number we mentioned feels like a much more balanced number going forward.

Hi, guys, so the inventory count.

Under normal conditions as just going up.

Got it yes, it feels like a good inventory number again going back we're not these aren't the days of two well pads, where if something bad happens you can pull on the pad and go somewhere else.

These are long cycle, many Danny let's call them, many offshore projects given the amount of dollars that go into a project before first oil comes online.

That makes sense.

Okay very good detail on all of the.

The cost trends across the various.

Buckets on slide 10.

Yes, if you think about going through RFP season for various services I know you have some longer term contracts in place but.

Do you think youll see any continued deflation across any of the major buckets as you go into 'twenty four or they're starting to.

Stabilized now.

Yeah, I think we think it's kind of stabilizing right now.

And for US there really is no RFP season, right RFP seasons everyday Diamondback, some things cheaper than we can do something cheaper or replace something with something cheaper. It can happen right away, it's not going away.

For next season or for the summer, it's going to happen now so it's a constant RFP season here and these are all real time cost the.

Team has to present to Travis.

On a line by line basis every quarter end.

This is a real time look at where we are and where things are headed as you noticed we've put our Q4 2023 number in there just to kind of show where even we've moved from from Q3 to Q4.

Got it appreciate the color. Thank you.

Thanks Scott.

Thank you one moment for our next question.

Our next question comes from the line of Leo Mariani of Roth <unk>. Your line is now open.

Okay.

I just wanted to follow up a little bit on 2024.

Im kind of reading this right. It looks like you guys are talking about.

Rob budget next year, just a hair over $2 $5 billion. It sounds like that is kind of flat activity just wanted to get a sense of kind of what's assumed in there for inflation or deflation are you just kind of assuming sort of current.

All costs in that number.

Yes.

And are a little conservative here Leo so it today.

Kind of in the range of where we think we are today again, we think generally service costs have kind of bottomed or flattened out and.

Absent a major change in rig count this feels like a pretty good.

It's a pretty good range for.

For next year.

Okay.

And then just to follow up quickly on the M&A topic here.

We've made it pretty clear that.

Wanted to continue to be a consolidator over time with your cost advantage I guess at the same time, just kind of I know you guys talk about kind of a $60 type of budgeting case for oil obviously been above there is there any scenario where.

<unk> thinks about potentially going the other way and actually selling at the end of the day.

Leo I tried to address it a little bit in my opening comments as one of the first questions and also.

In my letter look we'll always do the right thing for our shareholders. We have been I feel like we've done that for 12 years now.

But again, what our focus is on.

Delivering our business plan and we believe in our business model. We believe that there is a meaningful spot and our investment community for a company like Diamondback and we continue to execute flawlessly and I think I think I'm really really confident about what our forward.

Forward plan looks like.

Okay. Thanks.

Thanks Leo.

Alright, Thank you and one moment for our next question.

Next question comes from the line of Paul Cheng of Scotiabank. Your line is now open.

Alright, Thank you good morning.

Two questions from one.

One of the way to reduce cost I think the industry is moving full capitation.

Sean that wondering if you can give us some idea that how far along on your process.

So.

And secondly that with the deep pool.

I think in the past that you guys are very powerful in your infrastructure.

Infrastructure and all of that so is that signaling that now you have a change of view.

What kind of infrastructure and need to be on.

Or need to be controlled by <unk>.

Women back going forward. So should we just assume that this means that you really don't think that's necessary for you to have control or two one dose infrastructure. Thank you.

Yes, good question, Paul I'll take the second one first.

On the midstream infrastructure, we spent a lot of money building those systems to the specs that we needed and so I think we're not we're not turning over a blank canvas right. This is a painting it's already been <unk>.

Finishing touches and so we feel confident particularly with a lot of our field team members going over to deep blue to run the asset.

And that will be well well served as its largest customer and also a large equity holders. So I think if we are early in our development plan might be a different story.

But in this case.

So very well built out system that that is kind of ready made to turn it over to them too and our mines do some more things commercially that we couldnt do.

As a standalone water enterprise and then your other question I'll, let deprecation.

A hot topic in the Permian.

I think generally electrification means both lower cost and lower environmental footprint and Thats a great thing for us in this basin.

We've done a lot of work ourselves I think the state of Texas.

And the utilities need to kind of do their part to get more power out to the Permian to connect all of us. So that we can run off line power versus.

Different forms of generation in the field, so I think thats going to be a constant.

Constant battle that we are intently focused on in <unk>.

Again, it saves us money and improves environmental performance that feels like a win.

Just curious that I mean, what percent of your operation now that's already being in that check by in that where you think the biggest opportunity over the next one or two years.

Yes.

Got about 90% to 95% of our current production operations electric side, we've been the biggest opportunities we've been working on to date in the production operations world or been in electrification of our compression fleet and I think we're probably 70 ish percent electrified there so.

We will continue to work on.

Getting rid of our gas.

Gastroparesis compressors and putting electric packages in their place.

And then on the D&C side.

We've got to sign.

Donald Frac fleets that are halliburton, what they call their Zeus fleets, which are their electric fleets.

We've really enjoyed the benefits of those and look forward to continuing to try and electrify the completion world and then on the drilling side.

We've got I think five or six rigs running right now on online power and we're continuing to.

Put in the infrastructure that we need to to run those rigs offline power has a supply chain kind of freeze up in the back of Covid and we can get the electrical equipment, we need to.

The convert those rigs so it's kind of all over but but.

We're working on it as fast as we can in <unk>.

Anticipate that over the next four five years, there won't be much of the field thats not electrified.

Thank you.

Alright. Thank you. This does conclude the question and answer session.

I'd now like to turn it back to Travis Stice, Chairman and CEO for closing remarks.

I appreciate all the good questions. This morning I hope.

Veterans day, certainly for all of the veterans that are important one diamondback. Thank you for your service and then anyone that's on the phone, but also dedicated a portion of their lives.

Our country I wanted to tell you. Thank you for your service as well and then particularly for the Diamondback employees and hopefully we will see you at at breakfast or.

Ceremony is that we have planned for this Friday. So thank you all have a great day Douglas.

Alright. Thank you for your participation in today's conference. This does conclude the program you may now disconnect.

Q3 2023 Diamondback Energy Inc Earnings Call

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