Diamondback Energy Q1 2023 Earnings Call Transcript

Quartr
Provided by Quartr
May 2, 2023

There are 19 speakers on the call.

Operator

Good day, and thank you for standing by. Welcome to the Diamondback Energy First Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer 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, Vice President of Investor Relations.

Operator

Please go ahead.

Speaker 1

Thank you, Gioia. Good morning,

Speaker 2

and welcome to Diamondback Energy's Q1 2023 conference call. During our call today, we will reference an updated investor presentation and stockholder letter, which can be found on Diamondback's website. Representing Diamondback today are Travis Stice, Chairman and CEO Case Bantoff, President and CFO and Danny Westin, COO. During this conference call, the participants may make certain forward looking statements relating to the company's financial condition, Results of operations, plans, objectives, future performance and businesses. We caution you that actual results could differ materially from those that are indicated in these Forward looking statements due to a variety of factors.

Speaker 2

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. Now turn the call over to Travis Stice.

Speaker 1

Thank you, Adam. And Adam mentioned that we released a shareholder letter last night in conjunction with our press release. I hope you find that useful. We believe that it not only increases transparency directly to our shareholders, but also It improves efficiency. So we'll move right into questions.

Speaker 1

Operator, if you would open the line and begin with our first question.

Operator

Thank you. Please stand by for our first question. Our first question comes from the line of Neal Dingim of Truist Securities. Your line is now open.

Speaker 3

First, thanks, Travis, for the new format. I appreciate it. Travis, my first question is for you and Danny on one of the topic disorders that service cost. Specifically, are you able to quantify how your continued operational efficiencies have recently mitigated your cost? And Just wondering how you all think about spot versus long term contracts in the current environment?

Speaker 1

I think, Neil, the read through to that question is kind of what the CapEx is going to look like in the back half of the year. And I think there's And then I'll let Danny talk about the specific operational efficiencies we've seen year to date That's offset most of the inflationary pressures. But when we talk about deflation, it's really that's raw materials, It's diesel, it's sand, it's steel, particularly on steel because we're buying our steel needs Multiple quarters in advance. So we know what that steel cost is and it's already down for the future purposes $20 $25 a foot. And then we've also got the rigs we've talked about, we're going to drop a couple of rigs and that allows us To look at our entire rig fleet and the cost associated with those rigs and we see rig costs are coming down as well.

Speaker 1

And then lastly, while it's not necessarily a CapEx issue, we're seeing improved efficiencies as We've got that second eFleet that started last week, and we've also got rid of our 2 spot Frac crews and replaced them with 1 simul frac crew. So we're seeing $10 to $20 a foot efficiency gains there as well. So regardless, Neil, of what's going on with CapEx, our commitment has always been to be the low cost leader When it comes to prosecuting our development plan out here and we've got now almost a decade of demonstrating that. So we anticipate We're going to continue to do that and that's what our shareholders should be comfortable in. And Danny, do you have some additional color for near term?

Speaker 4

No, I think Travis covered everything that we've kind of seen on the drilling services side and consumable side on

Speaker 5

the drilling

Speaker 4

side That's leading us to see leading edge calls coming down. And then on the completion side, just with the additional efficiencies from the Additional eFleets as well as the replacement, simul frac fleet replacing the 2 Traditional zipper fleets that we took over as part of the 2 acquisitions at the end of the year.

Speaker 3

Great. Thank you for that. And then my second question for Kei is on shareholder return, Kei. Specifically, it seems you all plan to stick to or you are sticking to that 75% Free cash flow payout. Can you give me your opinion on maybe why not pay more like some peers?

Speaker 3

And on the capital allocation part The shareholder return, is that plan still just to see what your stock price is doing versus the mid cycle or how do you determine that?

Speaker 5

Yes, Neal, we always kind of when we up the shareholder return program to 75% of free cash going back to shareholders, we thought The mix of 75 percent to equity and 25 percent to the balance sheet was a good mix. We still believe that's a good mix. I think when things are going well, Like they have the last couple of years, 75% feels like a max number to go back to equity while continuing to improve the balance sheet. Really the test of this new business model and returns return of capital based business model is when things go south and in a potential downturn, That's I think the time when we should be allocating more capital to buying back shares, reducing the share count a lot more efficiently than it is Even when things are going well out today. So we've kept a flexible return of capital program since the beginning.

Speaker 5

I think we like that and we keep that. And Q1 is an exact reason why we maintain that flexibility. We don't want to blow out the balance sheet to buy back stocks, but we also recognize that when your stock is down significantly in the quarter, Variable dividend doesn't matter. That's what we did in Q1 and allocated a lot more cash to the buyback.

Speaker 3

We're glad to see it. Thank you all.

Speaker 1

Thanks, Jeff.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Neil Mehta of Goldman Sachs and Co. Your line is now open.

Speaker 6

Yes. Good morning, team and again, thanks for the new format. First question was around Gas price realizations, obviously, they were softer in the quarter. There's some one time dynamics it felt like, but just curious on your views On how local gas pricing is going to play out here and what protections you guys have Built in place in order to mitigate pricing negativity?

Speaker 5

Yes, Neil, good question. I think it's 2 things, right? There's certainly the unhedged realized gas Prices for us that were weaker in the quarter relative to the expectations. Really a lot of that comprised a $15,000,000 true up payment Contracts that moved from selling at the wellhead to taking on our taking kind rights downstream. So it's kind of an intercompany Ishuva, I recognize it did hit gas prices for the quarter.

Speaker 5

What we've done from a hedging perspective and from a physical perspective to protect against Future gas price blowouts in the basin should think there's going to be periodic points of weakness throughout this year and next. We've had all of our Waha exposure in the basin, which is about 2 thirds of our gas through the end of 2024. And then the other one third of our gas gets a combination of Henry Hub and Houston Ship Channel prices. And then on the Henry Hub side, we have Protected with wide callers with a $3 floor, about 2 thirds of our gas this year in 2023 and probably a third of it next year. So in general, I think we tried to give the Street some guidance on future unhedged gas realizations and the hedging piece has been a tailwind for us Gas prices weaken both at Henry Hub and in the basin.

Speaker 6

Thanks for that, Kees. And then just follow-up On some of the recent acquisitions that you've done here that you've had them in your portfolio now for a couple of months, Just any update on how they're executing early thoughts on productivity and efficiencies that you're able to realize out of the new assets?

Speaker 5

Yes. That's a great question as well. I would say generally, Larry, we knew what we were getting. That asset is nearby all of our Existing production in Martin County, so that's as advertised. I think at the end of the day, when we look back at the Firebird acquisition in a few years, that's going to be one of the Better value deals we got, we estimated there's almost 500 locations on that acquisition without Even pushing the limit on upside locations and there's been some well tests where we've co developed the Lower Spraberry and the Wolfcamp A On the southern part of the position that gives us confidence that some of those upside locations are going to become Real locations that we're going to develop over time.

Speaker 5

2nd to that, the ops team, they're going into a new area. We're already completing or drilling a 15,000 foot lateral in sub-ten days on the new field. So everything It's going well on both those deals. I would say generally over time Firebird will prove to be one of the better deals we did because of the amount of Acreage that came with it and the upside from a geologic perspective.

Speaker 7

Awesome. Thanks guys.

Operator

Thank you.

Speaker 8

Thank you, Neil.

Operator

One moment for our next question. Our next question comes from the line of Arun Jayaram of JPMorgan Securities LLC. Your line is now open.

Speaker 9

Good morning, guys. We do appreciate the new format. So those were really helpful. My first question is on CapEx. Your first half CapEx guidance plus the 1Q actuals implies Around $1,360,000,000 in spending or about 52% of the budget, you talked about having line of sight To some meaningful declines in service costs.

Speaker 9

So I was wondering maybe, Kees, if you could describe your confidence on hitting, call it, the midpoint Of the range of $2,600,000 for the full year? And how does your cash I know you account for CapEx on a cash basis versus accrual basis, how does that influence the timing of CapEx in a rising service price environment versus when it's falling?

Speaker 5

Yes. Good question, Arun. On the cash CapEx thing, the prime example was Q2 of 2020. Well, I don't want to relive that particular quarter. We reduced our rig count from 15 or 23 rigs down to 6 and we had to pay for that in the Q2.

Speaker 5

So there's a big disconnect between accrued And cash CapEx, no, that's not the issue we face here, right? We're talking about things at the margin like a $50,000,000 or so reduction in run rate CapEx, which Is in my mind very achievable based on three things. Lower activity, we're going to reduce our rig count by 2 rigs As expected, end of this quarter through the back half of the year. 2nd, lower service costs and Travis broke those down into The drilling side, which is a significant reduction in raw materials and a smaller reduction in the service piece of the drilling side And on the other side of that DC and E line, completions down because of efficiencies, because of the high grading to 2 Zeus fleets with Halliburton And 2, Simon Pressley. And lastly, midstream infrastructure, we spent a lot of money on midstream building out our Martin County water system That's nearing its end, so that the whole system is connected and infrastructure generally slows down in the back half of the year.

Speaker 5

That's the line of sight we have. I feel very confident that those things are coming our way based on what we can see in the accrued numbers that we pay for Over the next 45 days to 60 days on the cash side and CapEx.

Speaker 1

Yes. And just again, Arun, to reiterate my Opening comment to the first question is that our commitment to our shareholders remain unchanged to be the Low cost leader in efficiency and in execution and that's certainly been our track record and that's what we anticipate going forward, but Our commitment hasn't changed regardless of what CapEx

Speaker 9

does. Great. Thanks a lot, Travis. My follow-up, Tim, we've heard about some industry activity in leasing in the Midland Basin in deeper zones. Can you remind us how your leases are structured?

Speaker 9

Do you have rights to those zones currently? And perhaps this obviously could have some positive implications for Venom. So I was wondering if maybe talk about how FANG's leases are structured and maybe positive implications for Venom?

Speaker 5

Yes, there's really no one size fits all to leases in the Midland Basin. I would say generally, we have most of our leases cover the Wolfcamp B, which is a deeper zone that's We'll get a lot more attention over the coming years and some lesser extent do we have the Barnett and Woodford covered. Now, We've been exploring the Barnett and Woodford on the eastern on the western side of the Midland Basin for a very long time now with our Limelight play. It seems that the Barnett and Woodford play is going to extend more into the actual basin, and that's something That we're involved in along with many other large peers testing that zone and looking at it for future development The end of this decade and the next decade. I will say generally that's the benefit of owning a lot of minerals is that we have The other side of our business card that is going to have a front seat to leasing any of those deeper rights should they be unleased throughout the basin.

Speaker 9

Great. Thanks a

Speaker 5

lot. Thank you, Arun.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Scott Gruber of Citigroup. Your line is now open.

Speaker 10

Yes, good morning. Turning back to service rates, the service companies I've been talking about a bifurcated market here for both rigs and frac pumps. And their characterization is that Yes, the highly efficient crews, the next gen kit, especially nat gas fuel rigs and pumps will largely maintain pricing, while it's going to be the legacy And or lower quality crews, where you'll see the more meaningful declines in rates. Is that how you see the market developing here? Or do you see more broad based reductions in pricing kind of across the spectrum?

Speaker 5

Scott, I think that's partially true. Certainly on the frac side, the higher quality equipment, the super spec e fleets, Those have real contracts associated with them with less wiggle room on pricing. So that's why we think generally we make more money We'll save more money there on the efficiency side. On the rig side, I think generally, if 10% of your market It's going away in a quarter or 2. It's going to have an impact on pricing.

Speaker 5

There's just no doubt about that. Leading edge rates certainly are lower. I think we've also proven in the past to do more with less when it comes to equipment on the rig side, particularly in the Midland Basin, where it's a lot easier to drill in general than other places around the country.

Speaker 10

Got it. And then just turning to operating costs, LOE came in at the low end of the range, we kept the full year. And then you mentioned the fixed price contracts for power. Just any color that you can provide And how operating costs should evolve over the course of the year given the outlook for natural gas And power and other things, chemicals, etcetera, that go into operating costs?

Speaker 5

Yes. Look, I think, obviously, we had a very Start to the year on LOE. We still feel good about the midpoint of that range mainly because not because of the power, but because of Some of our activity is moving to areas where we have water dedicated to 3rd parties, not ourselves. And so that has a little higher rate. And so we expect LOE to trend up a little bit in Q2, Q3 as some of those big pads on 3rd party areas are developed.

Speaker 5

But generally, We received a benefit in terms of gas prices on the power side to lock in a lot of power. I would say generally we've locked in about 75% of our expected power needs for the foreseeable future, that should keep LOE generally lower For longer and less exposed to the price spikes that we saw last summer.

Speaker 10

Got it. Appreciate the color, James. Thank you.

Speaker 5

Thank you, Scott.

Operator

Thank you. One moment for our next question. Our next question comes from the line of David Deckelbaum of Cowen. Your line is now open.

Speaker 11

Good morning. It's Travis Case with Denny and team. Thanks for taking my questions today.

Speaker 1

Sure. Good morning, David. Morning.

Speaker 11

Just longer term from an efficiency gains perspective, you all made some headway and you highlighted the benefits Of using e fleets and moving that second e fleet this year, how do you think about as we progress into 2024 and 2025, the Between Simulfrac fleets and e fleets if we assume sort of this flattish rig count or is the 2 to 2 mix The expectation for longer term development?

Speaker 4

Yes, David, good question. I think Our plan right now looking out into 2024, 2025 is probably to stick with the kind of fifty-fifty mix. We Basically, have to underwrite the fleets and sign up for a longer term commitment with them, which is a little harder to do 100% of your capacity committed for a long term commitment, but The additional simulfrac fleet as more e fleets come to market and are available in a, I guess spot basis, we would certainly migrate to more eFleets, that we'd have some flexibility around utilization.

Speaker 11

Got it. And then my second question is around asset sales. You already did around 7 $73,000,000 or so that you point out that you've exceeded your target. You guys also highlight the remaining 5 or so outstanding investments that You're articulating on slide deck in the back, mostly on the midstream side, might be a source of funds going forward. Could you place like a is there a high probability that we'll see another asset sale this year?

Speaker 5

Yes. I would place a pretty high probability on that, David. We wouldn't have increased our target from $500,000,000 to 1,000,000,000 Of non core divestitures, if we didn't have pretty good line of sight, I can't guarantee it's going to happen today, but certainly there's a few things in the works Either on the JV side or some of the small operated midstream assets that could be up for sale. So we still feel very comfortable with that $1,000,000,000 target, I would just say it's tailored more towards midstream versus upstream.

Speaker 11

Appreciate it. Thanks for the time guys.

Speaker 5

Thank you.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Roger Read of Wells Fargo Securities. Your line is now open.

Speaker 2

Joey, let's move to the next question, please.

Operator

One moment for our next question. Our next question comes from the line of Kevin McCurdy of Pickering Energy Partners. Your line is now open.

Speaker 5

Hey, good morning. With the 1Q release, you've kind of given the pictures to figure out what the 4Q 2022 or 2023 CapEx and activity is. As we look into potential 2024 maintenance CapEx program, is the 4Q activity kind of a good Activity in CapEx is a good starting point or would you

Speaker 12

need to add any activity to

Speaker 5

keep production flat next year? Well, that's a good question, Kevin. I'm not Totally ready to commit to 2024 today, but I would say if we had to commit today, running some sort of plan with 4 Simulfrac crews is probably the most efficient and capital efficient plan we can put together. Now whether that spits out Slight growth to flat production is to be determined, but I think generally running this capital efficient plan without changing Activity levels too much and letting growth be the output has been, I think, rewarded Over the last couple of years with this new business model and that's kind of where we're circling things going forward. Great.

Speaker 5

That's the only question for me. Thanks, guys. Thank you, Kevin. Thanks, Kevin.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Derrick Whitfield of Stifel. Your line is now open.

Speaker 13

Good morning all and congrats on a strong start to the year.

Speaker 2

Thank you, Derek. Thank you, Derek.

Speaker 13

Building on an earlier question on Waha price weakness, could you perhaps elaborate on the degree of tightness you're projecting with in basin fundamentals?

Speaker 5

Yes. Derek, good question. I think generally, we're going to see very A lot of volatility and some pockets of extreme weakness. Obviously, there's a few expansions coming on, 3 expansions The back half of this year and the beginning of next year ahead of a large pipe coming on at the end of 2024, I just think the issue To date have been masked in the field as processing capacity in the field was short. Now that that processing capacity is coming on The tune of a Bcf a day or more, that's going to push the problem downstream to the downstream residue pipes.

Speaker 5

So I think it's coming. It's going to be pretty weak for periods and then pressure will be relieved a little bit when these Expansions come on, but generally, our take is let's remove our risk To that pricing weakness by hedging everything through 2024 and getting more physical molecule for the Gulf Coast. Ideally, We'd like to have control of all of our molecules in the Gulf Coast, but most of our contracts we inherited from deals that we bought and have not come with taking kind rights And we've worked to improve that over time and control more of our molecules further downstream.

Speaker 13

Great. And then as my follow-up, I wanted to touch on well productivity, which has been a positive development for you guys. Referencing Slide 14, could you speak to your expectations for 2023 well productivity relative to 2022? And how does that project over the next couple of years as you think about the integration of Xelerio and Firebird Acquisitions?

Speaker 5

Yes, good question. I think we said multiple times to investors, Flat for 2022 is probably the base case and we do a little better. That's one for the good guys. I think we're on pace for that, Particularly in the Midland Basin where we've had a really strong start to the year. And I would just say Firebird and Lario only Enhance that ability to do that for longer.

Speaker 5

At the end of the day, as we've said before, the shale cost curve is going up. It's our job to make sure we have the inventory duration and the cost structure to be at the low end of that shale cost curve, We've done well for the last 10 years and we expect to do well for the next 10 years.

Speaker 13

Well done, guys.

Speaker 1

Yes, Derek, Derek, I think it's just to reiterate that point that I've made a couple of times now about Diamondback's commitment to our shareholders about maintaining the lead and Efficiency and cost execution, it's exactly what Kees just said.

Speaker 13

Thanks for the added color, Travis.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Scott Hanold of RBC Capital Markets. Your line is now open.

Speaker 14

Hey, thanks. Could you all provide a little bit of color on the cadence of Moving forward, I mean, you all talk about having some larger pads going forward. And you all have had a very Smooth production trajectory. Did some of these large pads, will that create some lumpiness or is there some timing considerations we need to think about as we See those being developed?

Speaker 5

Yes. Good questions, Scott. I would say internally it certainly does. This business is not easy To grow consistently and hit numbers consistently, but externally, we think we're going to grow Fairly smoothly organically through the back half of the year. In general, our target is Turned about 85 wells to sales a quarter.

Speaker 5

Some quarters are going to be a little higher, some are a little lower based on timing. But In general, that's our job, right? It's there's a lot going on beneath the surface and that's what makes the Diamondback operations team the best in the business.

Speaker 14

Great. And then if we could talk about M and A a little bit and it looks like some of the private Private equity companies are dropping rigs in the Permian. And obviously, there have been some sales and talks of more sales coming up. Like what are you all seeing On the private side in terms of activity and what's your interest level in looking at some of these additional M and A opportunities?

Speaker 1

Yes, we've commented a couple of times about the increase in activity through 2022 was largely driven by Independence and the challenge there is depth of inventory, right? And the secondary challenge is How much can an increase further beyond their MAX cadence that they achieved last year? And I think both of those are playing out now. The MAX cadence may be Softening as you see by rigs getting laid down and certainly the inventory depth is getting accelerated with this rapid pace of bringing wells to production. So I think from an M and A perspective, it's going to be an interesting time over the next Couple of years, as these entities, the small ones, privates, trying to figure out a way to monetize.

Speaker 1

And I think you've also got while the catalyst is unclear, you've also got some small cap public companies That are going to need to figure out some form of exit strategy to be continued to be relevant in the future. And then there's always the large private unicorns that still float around out there as well too. So I really think that The next couple of years are going to be interesting in the M and A landscape.

Speaker 14

Yes. So do you believe though that some of these private equities that have burned through a lot of their acreage, Does that make it does the inventory factor make it less interesting to you all? Or is there a case to be made if you can buy PDPs cheap enough and Manage them down there in interest?

Speaker 1

Well, Scott, when you do M and A and if you do it correctly, You want to extend inventory life, you want to make sure that your free cash flow or cash flow accretive and you don't want to impact your balance sheet. Just doing PDP type acquisitions, not necessarily fit into that calculus, But it's I think that's what you're going to end up seeing with some of these exit strategies are just kind of straight PDP divestitures.

Speaker 14

Fair enough. Thank you.

Operator

Thank you. Thanks, Scott. One moment for our next question. Our next question comes from Jeffrey Lundbladgen of TPH. Your line is now open.

Speaker 12

Good morning, everyone, and thanks for taking my questions. Hey, Jeff. My first one is just on commentary in the supplemental release That talked about the trend continuing this year in terms of the large high NR iPads coming on in the Northern Midland Basin. Is there any additional color you can give there in terms of how the mix Of the total program going to that type of acreage where you might have much less surrounding development compares to that same mix or waiting To that type of acreage last year and just how to think about that mix over the near term?

Speaker 5

Yes, it's a good question, Jeff. I would say, The mix of undeveloped ESUs is probably similar to years past. Now the quality of the location of those undeveloped ESUs is Probably a little bit higher this year than in 2022 even. So it was kind of related to our comment on productivity. There's certainly a line of sight to very high productivity this year from development in the middle of Martin County.

Speaker 5

And Some of that we have up to a 6% or 7% NRI on large pads at the Viper level. And so Because we report consolidated financials, that is a benefit to the total enterprise Where that high NRI development is going to drive organic production growth at the entity.

Speaker 12

Great. I appreciate that. And then on the services side, certainly appreciate the detail just around where you see potential improvements and The timing around that throughout the year, I was just hoping you could speak maybe high level to how your contracts are set up, I guess, across the services spectrum, just to give a sense for How some of these improvements will layer in for Diamondback specifically over the course of the next couple of quarters?

Speaker 5

Yes. I think on the rig size, everything is kind of a rolling 3 to 6 month contract. So we see we can see that our Q2 average day rate is down from Q1 today. And so that's going to continue to come our way on the rig side. On the frac side, our 2 e fleets on the silanebraves e fleets We're pretty locked up on pricing.

Speaker 5

I would say, we saw some weakness in the spot frac pricing in Q1 versus Q4. And as we move those other 2 fleets to, simulcast fleets, I think the more benefit will be on the efficiency side Then the price per horsepower side, but generally a simulfrac fleet saves up $20 or $30 a foot Regardless of the price of the actual horsepower.

Speaker 1

Jeff, in addition to that, we talked earlier about Purchasing steel multiple quarters in advance. So we're seeing the steel that we're purchasing for our 3Q, 4Q, 1Q costs Already coming down. And so while it's not necessarily a service cost deflation, it is a cost deflation that's It could be as much as $20 or $25 a foot additionally.

Speaker 12

Appreciate it guys. Thank you.

Speaker 10

Thanks, Jeff.

Operator

Thank you. One moment for our next question. Our next question comes from the line of John Freeman of Raymond James. Your line is now open. Good morning, guys.

Speaker 1

Hey, John.

Speaker 15

You all had in 4th quarter, when you all are running ahead of schedule and you moved some of those pops The Q4 into the Q1 and just given all the commentary on the big efficiency gains on the simul fracs as you now go to Tord 4 was funnel stack abilities. If we end up in a similar spot where you have efficiency gains later this year, Is it likely that you all would and again, it's a first class problem, but would you similarly make a decision like last year where you would sort of don't pump the brakes in the right word, but maybe slow down a touch so that the budget is intact or you just sort of Plow ahead with the efficiency gains and just bring more wells online.

Speaker 5

No. Listen, I think we're highly incentivized to hit the budget. I think highly incentivized to increase free cash flow, which is part of the new business model, which issues growth for Returns and that's been the mentality. It's been a working mentality, a mentality that has worked for the last couple of years. It would be a 1st class problem.

Speaker 5

We're still early in the year, but generally that would be the plan. Now, I think the only nuance to that is we would like To keep rigs running and building docks, particularly if rig costs are a little bit lower than they are today.

Speaker 15

That's great. And then, really appreciate all the detail and color you have given on there. The service cost front, so Does it sound like obviously things are coming down from the peak levels of 1Q, but is it are you all basically indicating that You all are on track to potentially have lower total completed well costs by year end 'twenty three versus year end 'twenty two. Like you factor in what you're seeing on the cost side, but maybe more importantly, the efficiency gains from the simul fracs?

Speaker 5

Yes. I would say, yes, that's a fair answer. I mean, particularly, listen, steel is the biggest driver. I'm not we're not forecasting A total capitulation in service costs here, but when steel went up for 9 quarters in a row to over $110 a foot, We see in Q3, our steel costs are going to be closer to $90 a foot. So I mean that in itself makes up for a Significant percentage of the savings.

Speaker 5

So I would say, yes, Q4 2023 well costs below Q4 2022 Because generally Q4 2022 and Q1 2023 were the highs.

Speaker 15

That's great. Appreciate it guys.

Speaker 1

And John, listen, just to reemphasize, we run the business to maximize efficiency as well. And so Kaes made the point that Whether it's on the rig side or the completion side, we're about efficiency because we think that that's the Greatest driver of shareholder value in a business where you'll control the price of the product that you produce.

Speaker 15

Thanks, Travis.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Tim Rezvan of KeyBanc Capital Markets. Your line is now open.

Speaker 16

Good morning, folks. Thank you for taking my question. I wanted to circle back Dave's questions previously on asset sales. I'm sure you won't give a good answer on the Bloomberg story about Pecos County, but I think it highlights the number of levers that you can pull You got to $1,000,000,000 or more on asset sales. So trying to understand that, Kaes, what do you think a good Kind of target debt level is, do you think about it in terms of leverage or an absolute debt metric, as you compare yourselves to the large cap Peers.

Speaker 16

And I guess, why wouldn't you go bigger than that $1,000,000,000 given you're not allocating a lot of capital to the Delaware right now?

Speaker 5

Yes, Tim, that's a good question. I'm not going to go bigger because we want to beat the number, first of all. But Second to that, listen, the Delaware Basin overall still produces a lot of barrels and a lot of cash flow for us. And that's important to The credit ratings, it's important to our free cash flow forecast and all the above. So I think We have sold a few small things in the Delaware on the acreage side and the recurring theme of what we sold is that someone paid for upside.

Speaker 5

So we're not going to sell PDP cheap just to sell PDP. At the end of the day, someone has to pay for upside and pay for a faster pace of development Than we were expecting. And that I think has been a common theme in the Delaware deals as well as the deal in Glasscock County. Not only they pay PDP, but they paid for some PUDs that didn't compete for us in the next 10 year plan. So if that happens, then we'll look at Do what's right for our shareholders and look at divesting more in the Delaware Basin.

Speaker 5

But generally, that production and cash flow has a lot of value to us today.

Speaker 2

Okay. And then just

Speaker 16

getting back to that number, in an ideal world, how do you think about what is the right debt Number is whether either in debt or in leverage terms versus Yes, I'm sorry,

Speaker 5

I apologize, I forgot Reply to that part of the question. I think we think about debt in terms of 2 ways to think about it, right? Not only absolute debt and the leverage ratio, but also duration. And I think we obviously want less debt over time, but we feel comfortable with The amount of duration we have between now and our next maturity, which is 2026. So I'd like to take that out so that Travis won't bother me about it until 2029.

Speaker 5

And, but when we have extra free excess free cash flow, we're going to use it to reduce absolute debt. I think in a perfect world, a turn of leverage at a $55 or $50 oil price would be in my mind Ideal debt level with no debt due for multiple years before your next maturity.

Speaker 4

Okay. I appreciate the color. That's all I had. Thanks.

Speaker 1

Thanks, Tim. Thanks, Tim.

Operator

One moment for our next question. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.

Speaker 17

Good morning, Travis Case and to the rest of Diamondback team there.

Speaker 1

Hey, Charles. Good morning, Charles.

Speaker 17

Travis, this may be for you. Yes, I like the new format as well, but the I was also thinking about the shareholder letter. And Travis, in your prepared comments, I think you said, you were hoping this format would be more efficient To pick up on a big thing for you this morning, but I found myself wondering also, does this the iteration on your Communication style, I mean, does this also reflect an element of maybe dissatisfaction with how either your story is being understood or The traction that you're getting or that you maybe you'd be like you're getting that you're not. And if that is true or if that's the case that there's some element of it, what do you think the market might be missing?

Speaker 1

No, we didn't put this letter in place Trying to fix the communication issue. We've got incredible transparency communication format that we have with our shareholders. We just thought that based on a decade of doing these earnings calls And the lack of attention really paid in the prepared remarks felt like we could remove that. And we also know that other industries We're well ahead of the oil and gas sector by not doing prepared remarks. The other thing is that we could communicate more In this shareholder letter than what we traditionally would put in a truncated CEO quote in the earnings release.

Speaker 1

And then we didn't have to have anybody spending Sunday night preparing our transcript either as well too. So I mean from a Staff perspective, there's a lot more efficient there. So no, we did this because we think it's a better way to communicate, not that we need to improve The message or the understanding in our stock price.

Speaker 5

I think it also allows us to talk directly to our shareholders, right? Because A lot of the times the sell side is in control of narrative and this allows us to tell a little bit of the story Behind the numbers directly to our shareholders.

Speaker 17

Insight into your thinking. I appreciate that. And in case, I want to go back to the Question on the buybacks. I know this has been addressed at least in one other earlier question. But all other things being equal, and I know I recognize they never are, But all other things being equal, the shift to buybacks that we saw in 1Q, does that kind of signal A durable shift or if not a durable shift, a durable change in the preference towards buybacks?

Speaker 5

Yes. Listen, I think our preference has always been to buy back shares. Now what we wanted was a governor On what fundamentally are we buying back shares for? Are we buying back oil in the market cheaper than we can buy it in the ground? And that's our NAV versus looking at a deal like Lario or Farber.

Speaker 5

So at the end of the day, we're still going to run our NAV at a conservative mis cycle deck, which is $60 oil and the market has presented us opportunities to buy back shares every quarter Since we started this buyback program. So at the end of the day, again, our preference is buybacks, but we have a little bit of a governor on what Share price, we're going to be aggressive on and Q1 was the perfect example of that.

Speaker 1

And Charles, we've tried to be Mindful of since of the past our industry has been known for, which is oil price goes high, free cash flow goes up and share repurchases are done Not countercyclically like we're trying to do so, but in cycle with higher oil prices and that hasn't created a lot of value. We may not always be perfect in that calculus, but as Cees pointed out, whether it's the banking crisis here recently or Other forms of volatility, we've had an opportunity to purchase $2,000,000,000 worth of shares back at roughly $120 a share. So We feel like we're following through on our commitment of not only being flexible in our return program, but also being mindful of The method and the timing at which you refer to shares.

Speaker 17

Thank you, gentlemen. Appreciate the color.

Speaker 5

Thanks, Charles.

Operator

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

Speaker 5

Yes. Thank you. Good morning. Good morning, Roger. Let's go back and try

Speaker 7

and dig into the service cost and Deflation, I guess, we could call it at this point, we aren't so used to using inflation.

Speaker 5

Can you talk to us

Speaker 7

a little bit as you think about well costs being lower in the 4th quarter, how much of that is efficiencies and how much of that is just a decline in the cost of doing Something being drilling rigs or whatever? Fifty-fifty, fifty-forty, eighty-twenty, something like that

Speaker 18

as well. I was curious.

Speaker 5

I would say it's a quarter efficiencies and 75 percent actual costs. Now of the 75%, I would Say 2 thirds of that is due to raw materials and the other third is due to the actual service piece of the equation.

Speaker 7

Okay. Yes, that's helpful. And then the other follow-up question I had was, is there any sort of rule of thumb Approach you use as you switch to eFleets or as you went from the zipper frac to the saddle frac In terms of, however you want to think about it, stages per day, cost per stage, something like that. Again, just trying to understand some of these Changes as they get applied all across the entire complex?

Speaker 5

I'll give you the cost estimates and Danny can give you the efficiencies. I'd say generally a simulfrac fleet is $20 to $30 a foot cheaper than a conventional fleet and e fleet Is $20 to $30 a foot cheaper than a simulafrac fleet?

Speaker 4

Yes. I mean, in each fleet, we're utilizing our simulafrac fleets. They're just powered with electric power that we generate on location or that we pull off the grid. Really the savings on the eFleet comes from the fuel consumption fees and just being more efficient on location. We do think we see a little bit of disparity between the kind of lateral footage completed per day By the eFleets versus the diesel, simulafrac fleets, but we don't have a just ton of data yet to quantify that.

Speaker 4

But We are hopeful that over time the e fleets will kind of widen the gap of execution efficiency Just because of the lower maintenance and R and M stuff that's required on location.

Speaker 1

Dan, the difference between Zipper And simulfrac in terms of footage per day, do you have a

Speaker 4

Yes, I mean, so we kind of say a simulfrac fleet, depending on the jobs, can do about Twice as much lateral footage per day as a traditional zipper fleet.

Speaker 7

Yes, so very, very large differences. One just little clarification on your comment at the very beginning about locking in some of your electricity costs, being able Predict your LOEs a little better during the summer. Is there any interruptible risk with those contracts? I mean, I'm not talking outages, which would affect everybody, but just to get the lower cost or fixed cost, you have to accept The risk of being turned off?

Speaker 4

No, it's just a hedge in the market. So It's just a financial hedge, not a physical trade.

Speaker 5

Great. Thank you.

Operator

Our next question comes from the line of Leo Mariani of ROTH MKM. Your line is now open.

Speaker 5

I just wanted to follow-up

Speaker 18

quickly on LOE. I just wanted to clarify one of your earlier comments. It sounds like you guys are expecting LOE per barrel decline here in 2Q and 3Q versus where you were in 1Q. Just to make sure I

Speaker 12

sort of heard that right.

Speaker 5

No, we expect it to go up to the midpoint of guidance from $5 to midpoint of $5 to $5.50 So Going up slightly due to 3rd party water handling.

Speaker 18

Okay. And you're viewing that is somewhat temporary just based on are the rigs are going to be sort of be drilling location wise here in the middle part of the year?

Speaker 5

Yes, just depending upon where the completions are. Completions are on a 3rd party dedicated piece of acreage. The cost is higher than it would have been on a prior Rattler dedicated piece of acreage.

Speaker 18

Right. Okay. And then just on cash taxes, looking at Q1, you guys kind of came in below the guidance. So far, I guess, quarter to date here in 2Q, commodity prices are kind of flat to down. You guys are expecting cash tax It's a kind of increase here in QQ per the guidance.

Speaker 18

Just wanted to kind of get a little bit more color in terms of how The year plays out, I mean, you generally see cash taxes increasing throughout the year and then maybe that just has to do with NOLs that are completely disappearing or other tax But any other color kind of around that cadence of cash taxes as the year progresses?

Speaker 5

Yes. I think the only real added benefit that Q1 had versus Q2, even if commodity prices were flat, is that we closed LEREO in the quarter And I got to write off some of that, the hard assets that came with that right away.

Speaker 18

All right. So it sounds like it's just M and A driven on the Tax Shield side and now maybe 2Q is more of a normal representative rate going forward?

Speaker 7

That's fair. Okay. Thank you.

Operator

Thank you. One moment for our next question. Our final question comes from Paul Cheng of Scotiabank. Your line is now open.

Speaker 8

Thank you. Good morning.

Speaker 4

Just want to add my appreciation with the

Speaker 8

new format. I think it's great. Two questions, please. First, you've been increasing your overall foot Activity in the Midland over the last several years. So now you have 85%, 15% between the two.

Speaker 8

Should we assume this is going to be pretty steady and stable for the next several years or that you may start to doing more there well, Say, maybe sometime over the next 1 or 2 years?

Speaker 5

I think over the next few years, the $85,000,000 is a very fair Yearly estimate, obviously some quarters will be higher than others. We want to continue to complete Multi well pads in the Delaware. So you have a quarter like Q1 of 2023, which was higher Delaware when Q4 was 0 wells in the Delaware. But On an annual basis, $85,000,000 feels like the right lateral footage mix.

Speaker 8

Okay. And the second question is that you talked about the Patrick, you feel very comfortable about the midpoint for the full year. Just curious that in that budget, how much is the cost Saving or that the you're talking about the line of sight of the cost is coming down. How much of them is already originally built in Going to be below the midpoint of your budget and not?

Speaker 5

I don't know if I'm ready to commit to that Today, Paul, we certainly have some work to do, but we have very good line of sight from an activity and a cost perspective that We've seen the peak in well costs and a little bit of a tailwind from the activity of 2 rigs coming down. Now I think that will happen a little bit in Q3 and more in Q4, but it's still early.

Speaker 8

Okay. Can you share with us that, I mean, how much of the savings you originally built in or how much is the deflation in

Speaker 16

the second half Ted, you have

Speaker 8

built in into your budget?

Speaker 5

I would say if we saw more service cost Deflation, that would be upside to what we've modeled here.

Speaker 4

I see. That's true. That's true.

Speaker 5

Not raw materials.

Speaker 4

Okay. We do. Thank you.

Speaker 5

Thank you, Paul.

Speaker 3

Thank you.

Operator

This concludes our Q and A session. I would now like to turn it over to Travis Stice, CEO for closing remarks.

Speaker 1

Thank you for joining us this morning. I think another benefit of this new format It is to allow more questions based on the amount of questions we had this morning. So if you have any additional follow-up that you need, just reach out to us using the numbers that we provided earlier. Thanks again for joining. Have a great day.

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Earnings Conference Call
Diamondback Energy Q1 2023
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