Q1 2023 Diamondback Energy Inc Earnings Call
Speaker 1: Right.
Speaker 2: Four.
Speaker 3: 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.
Speaker 3: 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 1 1 on your telephone, and you will then hear an automated message advising your hand is raised.
Speaker 3: To withdraw your question, please press star 1-1 again.
Speaker 3: Please be advised the state's conference is being recorded.
Speaker 3: I would now like to hand the conference over to your first speaker today, Adam Lawless, Vice-President of Investor Relations. Please go ahead.
Speaker 4: Thank you, Gioia. Good morning and welcome to Diamondback Energy's first quarter 2023 conference call. During our call today, we will reference an updated investor presentation in stockholder letter which can be found on Diamondback's website.
Speaker 4: Representing Diamondback today are Travis Dice, Chairman and CEO , Case Mantholf, President and CFO , in Dany West, and CFO . During this conference called the Participants Maynays, so in four living statements relating to the company's financial condition, results of operations, plans, objectives, future performance and businesses.
Speaker 4: We caution you that actual results get different material from those that are indicated in these board looking statements due to variety of factors.
Speaker 4: Information concerning these factors can be found in the company's filing of SEC.
Speaker 4: The affiliations with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon.
Speaker 4: I'll tell you the color of the chat. Thank you, Adam, and Adam mentioned that we released a shareholder ledger 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...
Speaker 4: It improves efficiency. So we'll move right into questions. Operator, if you could open the line and begin with our first question.
Speaker 3: Thank you. As a reminder to ask a question, you will need to press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 again.
Speaker 3: Please stand by for our first question. Our first question comes from the line of Neil Dingham of Truist Securities. Your line is now open. Thank you for your time.
Speaker 4: First, thanks Travis for the new format that I appreciate it. Travis, my first question for you are Danny on one of the top of visitors that service costs. So civically, are you able to quantify how you're continued operational efficiencies have recently mitigated your cost? Now we'll get our vaccination when we get
Speaker 4: Just wondering how you all think about spot versus long-term contracts in the current environment You know, I think Neil the read through that question is you know kind of what the capex is going to look like in the back half of the year and You know, I think there's in it and I'll let Danny talk about the specific operational efficiencies we've seen, you know, year to date that's offset most of the inflation.
Speaker 4: 20, 25 dollars a foot. And then we've also got, you know, the rigs we've talked about, we're gonna 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 4: And then lastly, while it's not necessarily a CapEx issue, we're seeing improved efficiencies as we've got that second E-fleet that started last week.
Speaker 4: And we've also got rid of our two spot frack crews and replaced them with one cymbal frack crew. So we're seeing you know 10 to 20 dollars of foot efficiency gains there as well. So regardless of what's going on with CapEx, you know our commitment has always been to be the low-cost leaders.
Speaker 4: when it comes to prosecuting our development plan out here. And we've got now almost a decade of demonstrating that. So we anticipate that we're going to continue to do that, and that's what our shareholders should be comfortable in. Sandy, 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, a consumable side on the drilling side, that leading edge calls coming down. And then on the completion side, just with the additional efficiencies from the additional e-for-each.
Speaker 4: as well as the replacement, somaphrac fleet replacing the two traditional zippered plates that we pick over as far as the two acquisitions at the end of the year.
Speaker 4: Great, thank you for that. And then my second question for Kay is on shareholder return. Kay, 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 and on the capital allocation part of the shareholder return? Is that plan still?
Speaker 4: percent to the balance sheet was a good mix. We still believe that's a good mix. I think when things are going well, I'd like to have the last couple 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 in returns.
Speaker 5: Our next question comes from the line of Neil Mehta of Goldman Sachs & Co. Your line is now open. Yeah, good morning team and again thanks, thanks for the new format. The first question was around gas price realizations. Obviously they were soft in the quarter. There's some one-time dynamics it felt like but you know just you're curious on your views.
Speaker 5: 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 negative.
Speaker 4: Yeah, Neil, good question. I think it's two things, right? There's certainly the unhedged, real-life gas prices for us that were weaker in the quarter relative to the expectations. Really a lot of that comprised a $15 million true-up payment between a contract that moved from
Speaker 4: selling at the well head to taking on our taking kind rights downstream. So it's kind of an inter-company issue, but I recognize it did hit gas prices for the quarter. You know, what we've done from a from a from a from a hedging perspective and from a physical perspective to protect against future gas price loss and the basins. We think, you know, there's going to be periodic.
Speaker 4: points of weakness throughout this year and next. You know, we've had all of our Waha exposure in the basin, which is about two-thirds of our gas through the end of 2024. And then the other one-third of our gas gets a combination of Henry Hubb and Houston Ship Channel prices.
Speaker 4: And then, you know, on the Henry Health side, we have protected with, you know, wide collars with a $3 floor about two-thirds of our gas this year in 2023 and probably a third of it next year. So in general, you know, I think we try to give the streets some guidance on future unhedged gas realizations and the...
Speaker 6: The hedging piece has been a failing for us as gas prices weaken both at Henry Halvin interpretation. The
Speaker 5: Thanks for that case. And then just follow up on some of the recent acquisitions that you've done here. You've had them in your portfolio now for a couple months. Just any update on how they're executing, early thoughts on productivity and efficiencies that you're able to realize.
Speaker 6: 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. There's been some well tests where...
Speaker 6: We've co-developed the lower spray barrier in the Wolf Camp Bay 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. Second to that, the ops team, they're going into a new area.
Speaker 6: We're already completing or drilling a 15,000 foot lateral in sub 10 days on the new field. So everything is going well on both of 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.
Speaker 4: from a geologic perspective. Awesome. Thanks, guys.
Speaker 5: Thank you. Thank you. One moment for our next question.
Speaker 3: Next question comes from the line of Aaron Gyram of J.P. Morgan Securities LLC. Your line is now open.
Speaker 4: Good morning guys. We do appreciate the new format. It was really helpful. My first question is on CapEx. Your first half CapEx guidance plus the one Q actuals implies around 1.36 billion in spending.
Speaker 4: about 52% of the budget you talked about having line of sight to some meaningful declines in service costs. So is there maybe a case if you could describe you know your confidence on hitting called the midpoint of the range of 2.6 billion for the full year and how does yeah your cash
Speaker 4: I know you account for CapEx on a cash basis versus a cruel basis. How does that influence the timing of CapEx in a rising service price environment versus when it's falling?
Speaker 6: April was Q2 of 2020. Why don't we live that particular quarter? We reduce our rig count from 15 or 23 rigs down to 6. We have to pay for that in the second quarter. So there's a big disconnect between accrued and cash catbacks. Now that's not the issue we face here. We're talking about.
Speaker 6: things at the margin like a $50 million or so reduction in run rate cap backs, which is in my mind very achievable based on three things. Lower activity, we're going to reduce our rig count by two rigs as expected at the end of this quarter through the back half of the year. Second, lower service costs and Travis broke those down intocake and then Melissa hardbased case Stewart.
Speaker 6: 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&E line completions down because of efficiencies, because of the high grading to two zoos fleets with Haliburton and two cymbal thracleets. And lastly, you know, midstream infrastructure, we spent a lot of money on midstream building out our Martin County water system.
Speaker 6: that nearing its end so that the whole system is connected and infrastructure generally slows down in the back half of the year. So that's the line of sight we have. It feels 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 to 60 days on the cash side and capex
Speaker 4: Yeah, and just again to, 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. Our commitment hasn't changed for...
Speaker 4: have rights to those zones currently and perhaps you know this obviously could have some positive implications for venom so wondering if you can maybe talk about how FAANG leases are structured and maybe positive implications for venom. Yeah there's really no one-size-fits-all to leases in the Midland Basin you know I would say generally
Speaker 6: We have most of our leases covered at Wolf Camp D, which is a deeper zone that's going to get a lot more attention over the coming years. And a lesser extent do we have the Barnett and Woodford covered. Now we've been exploring the Barnett and Woodford on the western side of the Midland Basin for a very long time now with our limelight fly. It seems that...
Speaker 6: 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, and the end of this decade and the next decade.
Speaker 6: 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 unleashed throughout the basin.
Speaker 5: Great, thanks a lot. Thank you. Thank you.
Speaker 3: One moment for our next question. Our next question comes from the line of Scott Gruber of Citigroup. Your line is now open.
Speaker 6: Good morning. Turning back to service rates. The service companies have been talking about a bifurcated market here for both rigs and track pumps and their characterization is that they have highly efficient clues and their next-gen kit, especially.
Speaker 7: And that gas fuel rigs and pumps will largely maintain pricing while it's going to be the legacy equipment and or lower quality cruise, you know, where you will see the more meaningful declines in rates.
Speaker 7: Is that how you see the market developing here? Do you see more broad-based reductions in pricing across the spectrum?
Speaker 6: You know, Scott, I think that's partially true. Certainly on the frac side, you know, the higher quality equipment, the super spec e-fleets, you know, those have real contracts associated with them with less wiggle room on pricing. So that's why we think generally we make more money.
Speaker 6: or save more money there on the efficiency side. On the rig side, I think generally, if 10% of your market is going away in a quarter or two, it's going to have an impact on pricing. There's just no doubt about that. So leading edge rates certainly are lower. I think we've also proven in the past to…
Speaker 6: in general than other places around the country.
Speaker 7: Got it. And then just turning to operating costs, we came in at the low end of the range. We kept the full year. And then you mentioned the fixed price contracts for power.
Speaker 7: If any color they can provide on how operating costs should evolve over the course of the year given.
Speaker 7: the outlook for natural gas and power and other things, chemicals, etc., that go into operating costs.
Speaker 6: Yeah, you know, look, I think obviously we had a very good start to the year on L.O.E. We still feel good about the midpoint of that range mainly because...
Speaker 6: Not because of power, but because some of our activity is moving to areas where we have water dedicated to third parties, not ourselves. And so that has a little higher rate, and so we expect LUE to trend up a little bit in Q2, Q3 as some of those big pads on third party areas are developed. But generally, we expect LUE to trend up a little bit in Q3, Q4 as some of those big
Speaker 6: We received a benefit in terms of gas prices on the power side to lock in a lot of power. Generally, we've locked in about 75% of our expected power needs for the foreseeable future. That should keep LWD generally lower for longer and less exposed to the price spikes that we saw last summer.
Speaker 7: Thank you.
Speaker 7: Got it for Jason color. Thanks. Thank you. Thank you Scott.
Speaker 3: Thank you. One moment for our next question. Our next question comes from the line of David Dekulbom of Cohen. Your line is now open.
Speaker 8: Thanks for taking my questions today.
Speaker 8: Morning Travis, Casey, Danny and team. Thanks for taking my questions today. Sure, good morning David.
Just a longer term from an efficiency gains perspective. You all made them headway and you highlighted the benefits of using E-fleets moving that second E-fleet this year. How do you think about, you know, as we progress into 24 and 25, the mix between the time of rack fleet and E-fleets if we assume sort of this flatish rig counter is the two-to-two mix.
the expectation for longer-term development.
Yeah, David, a good question. I think, you know, our plan right now looking out into 24, 25 is probably to stick with the, you know, kind of 50, 50 mix. We would basically have to underwrite the E bleat and son of for a long return commitment with them.
which is a little harder to do 100% of your capacity committed for a long-term.
commitment, but the additional, you know, Simulfract fleets as more e-fleets come to market and are available in, I guess, spot basis, we would certainly migrate to more e-fleets that we'd have some flexibility around utilization.
Got it.
And then my second question is around asset sales. You already did around 773 million or so the day 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 back 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?
Yeah, I would place a pretty high probability on that, David. You know, we wouldn't have increased our target from 500 million to a billion of non-court of estatures if we didn't have, you know, pretty good on the site. You know, I can't guarantee it's going to happen today, but certainly there's a few things that work, you know, either on the JB side or...
you know, some of the small operated midstream assets that could be up for sale. So we still feel very comfortable with that billion dollar target. I would just say it's tailored more towards midstream versus upstream.
Thank you.
Appreciate it. Thanks for the time guys.
Thank you. Thank you. One moment for our next question. Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.
Roger, you're on mute if you're on the line.
Do you have any words towing prayers? No, I won't.
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.
Hey, good morning. With the one-q release, you've kind of given the pictures to figure out what the 4q23 CAPEX activity is. And let's just do that, well, I think we're good.
As we look into potential 2024 maintenance CAPEX program, is the 4Q activity kind of a good activity in CAPEX, a good starting point, or would you need to add any activity key production plot next year?
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 four simulbrack crews is probably the most efficient and capital-efficient plan.
we can put together. Now, you know, whether that spits out slight growth to flat production is to be determined, but I think generally, you know, 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.
of Derek Whitfield of STIFL. Your line is now open.
Good morning all and congrats on a strong start to the year.
Thank you, Derek.
Could you perhaps elaborate on the degree of tightness you're projecting with in-basin fundamentals? Yeah, Derek, good question. I think generally we're going to see a lot of volatility and some pockets of extreme weakness. Obviously there's a few expansions coming on, three expansions.
You know the back half of this year in the beginning of next year ahead of a large fact coming on at the end of 2024 You know, I just think they're the issue to date had been masked in the field as processing capacity in the field was short.
now that that processing capacity is coming on, you know, the tune of the BCS a day or more, you know, that's gonna push the problem downstream to the downstream residue pipes. So I think if it's coming, it's gonna be, you know, 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 molecules to the Gulf Coast. Ideally, we'd like to have control of all of our molecules to the Gulf Coast, but most of our contracts we inherited from deals that we bought have not come with taking kind rights.
We've worked to improve that over time and control more of our molecules further downstream.
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 years as you think about the integration of Zillario and Firebird acquisition?
Yeah, good question. I think we said multiple times to investors, flat for 2022 is probably the base case and if 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 really strong...
start to the year. And I would just say Firebird and Lario only enhance that ability to do that for longer. At the end of the day, as we've said before, that the shell 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 shell cost curve, which we've done well for the last 10 years and we expect to do well for the next 10 years.
Well done guys. Yes, Derek, I think 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. That's exactly what Case just said.
Well done, guys. Yes, Derek. I think it just to reiterate that point that I've made a couple of times now about, you know, Diamondbacks, commitment to our shareholders about maintaining the lead and efficiency and cost execution. You know, it's exactly what Casey just said. Thanks for the Attickeller Travis.
Thank you.
Thank you. One moment for our next question.
Our next question comes from the line of Scott Hanold of RBC Capital Markets. The line is now open.
Hey, thanks. Could you all provide a little bit of color on the Keynes of Activity, you know, moving forward? I mean, you all talk about having some larger pads going forward. You know, and you all have had a very smooth production trajectory. Did some of these large pads, will that create?
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 to turn about 85 wells to sales a quarter. Some quarters are going to be a little higher, some are a little lower based on timing.
In general, that's our job, right? There's a lot going on beneath the surface, and that's what makes the Diamondback operations team the best in the business.
Great, and then if we could talk about M&A a little bit, and it looks like some of the private-to-private equity companies are dropping rigs in the Permian, and obviously there have been some sales and talks of more sales coming up. What are you all seeing on the private side in terms of activity, and what's your interest on federal funds?
inventory, right? And the secondary challenge is, you know, how much can an increase, you know, 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.
I think you've also got, while the catalyst is unclear, you've also got some small cap public companies that are gonna need to figure out some form of exit strategy to continue to be relevant in the future. And then there's always the large private unicorns that...
that still flow around out there as well too. So I really think the next couple of years are going to be interesting in the M&A landscape. 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, do the inventory factor make it less interesting to you all? Or is there a case to be made if you can buy PDP's cheap?
sheet. So you know just doing PDP type acquisitions you know doesn't necessarily fit into that calculus but you know it's it's uh 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.
Fair enough, thank you. Thank you. Thanks, Scott. Thank you for our next question.
Our next question comes from Jeffrey Lembudgen of TPH. Your line is now open. What is the largest picture Lao?
Morning everyone and thanks for taking my questions. My 1st 1 is just on commentary and the supplemental release that talked about the trend continuing this year in terms of the large high in our 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. Compared to that same mix, we're waiting to that type of acreage last year and just had to think about that mix over the near term.
Yeah, that's a good question, Jeff. I would say the mix of undeveloped DSUs is probably similar to years past now. The quality of the location of those undeveloped DSUs is probably a little bit higher this year than in 2022 even. We have to enthusiastically pavement, sir, when
And I was kind of related to our common on productivity. You know, there's certainly a line of sight to, you know, very high productivity this year from development in the middle of Martin County. And some of that, you know, we have up to a six or seven percent NRI on, you know, large pads at the Vyper 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.
Great, appreciate that. And then on the service 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 is to give a sense for how some of these improvements will layer in for dining back specifically over the course of the next couple quarters.
Yeah, I'd say on the rig side, everything's kind of a rolling three to six month contract. So we see, we can see that our Q2 average day rate is down from Q1 today. So that's going to continue to come our way on the rig side. On the frack side, our two e-fleets on the simulbrag e-fleets.
pretty locked up on pricing. I would say you know we saw some some weakness in the spot fracked pricing in Q1 versus Q4 and you know as we move those other two fleets to simul-fracked fleets you know I think the more benefit will be on the efficiency side than the price for horsepower side but generally a simul-fracked fleet.
saves up 20 or 30 bucks a foot, you know, regardless of the price of the actual horsepower.
You know, Jeff, in addition to that, we talked earlier about, you know, purchasing steel multiple quarters in advance. So we're seeing the steel that we're purchasing for our 3Q, 4Q, 1Q costs, you know, already coming down. And so while it's not necessarily a service.
It is a cost deflation that could be as much as $20 or $25 a foot additionally. Appreciate it, guys. Thank you. Thanks, Jeff.
Thank you. One moment for our next question.
Our next question comes from the line of John Freeman of Freeman James. Your line is now open.
Good morning, guys. Hey, John . Y'all are in fourth quarter. When y'all are running ahead of schedule and you move some of those pops from the fourth quarter into the first quarter and just given all the commentary on the big efficiency gains on the final practice as you now go to toward four with some of the fact 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 the first class problem, but would you similarly make a decision like last year where you would sort of, I don't know, pump the brakes in the right word, but maybe slow down and touch so that the budget is intact or you just sort of plow ahead with the efficiency gains and just bring more weld online.
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. I've been telling you that it has worked for the last couple of years. So.
You know, it would be a first-class problem. We're still early in the year, but generally that would be the plan now. I think the only nuance to that is, you know, we would like to keep rigs running and building ducks, you know, particularly if reed costs are a little bit lower than they are today.
That's great. And then really appreciate all the detail and color you all have given on there. The service cost front, so does it sound like obviously things are coming down from the peak levels of one queue, but is it, are you all basically indicating that any of those things could experience in the world that you happen to experience now?
Y'all are on track to potentially have lower total complete well cost by year and 23 versus year and 22 like when you factor in what you're seeing on the cost side but maybe more importantly the efficiency gains from the cymofracts.
Yeah, I would say yes, that's a fair answer. I mean, particularly, listen, Steel's the biggest driver. We're not forecasting a total capitulation and service costs here, but when Steel went up for nine quarters in a row to over $110 a foot. It wouldn't have actually taken a minute to average, and pretty much takes less that. That's because their speed ATV s
we see in Q3 our steel costs are going to be closer to $90 a foot. So that in itself makes up for a significant percentage of the savings. So I would say yes, Q4 2023 well costs below Q4 2022 because generally Q4 22 and Q1 23 were the highest.
That's great, appreciate it guys. And John , listen, just to re-emphasize, we run the business to maximize efficiency as well. And so case made the point that whether it's on the rig side or the completion side, you know, we're about efficiency because we think that that's the greatest driver of shareholder value in a business where you don't control the price of the product that you produce.
Thanks, Travis. Thank you. One moment for our next question. Our next question comes from the line of Tim Resvin of KeyBank Capital Markets. Your line is now open.
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 picos county, but I think it highlights the, you know, the number of levers that you can pull. You get to a billion or more on asset sales, so trying to understand that case, you know, what do you think a good.
you know, kind of target debt level layers. Do you think about it in terms of leverage or an absolute debt metric? You know as you compare yourselves to the large-cap peers, and I guess you know, why wouldn't you go bigger than that 1 billion? Given you're not allocating a lot of capital to the Delaware right now.
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, you know, 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 of the above. So I think...
You know, 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. 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 Glasgow County. Not only did they pay for 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 do what's right for our shareholders and look at divesting more in the Delaware Basin. But generally, we're going to be looking at the PDPs and the PDPs in the next 10 years.
that production and cash flow has a lot of value to us today. Okay, and then just getting back to that number, you know, in an ideal world, how do you think about the right debt?
number is whether either in debt or in leverage terms, you know, first. Yeah, sorry, I apologize. I forgot to reply to that part of the question. I think we think about debt in terms of two ways to think about it, right? Not only, you know, absolute debt and the leverage ratio, but also duration. And, you know, 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. 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, you know, an ideal debt level with no debt due for multiple years before your next maturity. Okay. I appreciate the colors that's all I had. Thanks.
55 or $50 oil price would be, in my mind, an ideal debt level with no debt due for multiple years before your next maturity. Okay. I appreciate the callers. That's all I had. Thanks. Thank you, Tim.
One moment for our next question. Our next question comes from the line of Charles Meade of Johnson Rice. Your line is now open.
Give me a Travis case and two, the rest of the dimeback team there. Hey, Charles, good morning, Charles. Travis, this may be for you. I like the new format as well, but I was also thinking about the shareholder letter. And Travis, in your prepare 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, 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 or the traction that you're getting?
or that you maybe feel like you're not. And if that is true, or if that's the case, but there's some element of it, what do you think the market might be missing? No, we didn't put this letter in place trying to fix the communication issue. We've got incredible transparency, communication format that we had with the standardooo hot wee loo
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.
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, it was 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. I think it also allows us to talk directly to our shareholders, right? Because, you know, a lot of the times, you know, the sell side is controlling the narrative and this allows us to tell a little bit of the story behind the numbers directly to our shareholders.
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 one queue to the other, I think that's a good thing. We're basically just trying to critical everything by going to the left-hand side.
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 Firebird. So at the end of the day, we're still going to run our NAV at a conservative mid-cycle deck, which is $60 oil.
and the market has presented us opportunities to buy back shares every quarter since we started this buy back program. So at the end of the day, again, our preference is buy back, 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. And Charles, we've tried to be mindful of sins of the past. Our industry has been...
known for which is old price goes high, pre cash flow goes up and share repurchases are done, you know, not countercyclicaly like we're trying to do so but the in cycle with higher old prices and that that hasn't created a lot of value so you know we may not always be working in that calculus but the less case pointed out whether it's the banking crisis here recently or
other forms of volatility. We've had an opportunity to purchase two billion dollars worth of shares back it, you know, roughly 120 bucks a share. So we feel like we're following through our commitment of not only being flexible in our return program but also being mindful of, you know, the method and the timing at which you revert to shares.
Thank you gentlemen, appreciate the color. Thanks Charles. Thank you. One moment for our next question.
Our next question comes from the line of Roger Reed of Wells Fargo Securities. Your line is now open.
Yeah, thank you. Good morning. Oh, Roger. Let's go.
dig into the service cost and deflation, I guess we could call it at this point. We aren't so used to using inflation.
Can you talk to us a little bit as you think about well cost being lower in the 4th quarter? How much of that is efficiencies and how much of that is. You know, just a decline in the in the cost of doing something being drilling rigs or whatever.
50-50, 60-40, 80-20, something like that is what I was curious about. I would say it's a quarter efficiency and 75% actual costs. Now, of the 75%, I would say two-thirds of that is due to raw materials and the other third is due to the actual service piece of the equation.
Okay. Yeah, that's helpful. Then the other follow-up question I had was, is there any rule of thumb approach you use as you switch to e-fleets, or as you went from the zipper frack to the saddle frack, 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. I'll give you the cost estimates and Danny can give you the efficiencies. Generally a Simulfrag fleet is $20 to $30 a foot cheaper than a conventional fleet and an E fleet.
is $20 to $30 a foot cheaper than a Simulfract fleet? Yeah, I mean, an e-fleet, e-fleets were utilized in our Simulfract fleets. They're just, you know, powered with electric power that we generate on location or that we pull off the grid. So, you know, really, the savings on the e-fleet comes from the fuel consumption piece and just being more efficient on location.
to widen the gap of execution efficiency just because of the lower maintenance and R&M stuff that's required on location.
The difference between zipper and summer frack in terms of footage per day. Yeah, I mean, so we kind of say a sound of frack plea, depending on the jobs, can do about twice as much lateral footage per day as a traditional zipper plea.
Yeah, it's a very, very large differences. 1, just little clarification on your comment very beginning about locking in some of your electricity costs, being able to predict your 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, you know, that to get the lower cost.
Thank you. One moment for our next question.
Our next question comes from the line of Leo Mariani of Roth MKM. Your line is now open. Thank you for having me again Mr. project.
I just wanted to quickly on LOE. I just wanted to clarify one of your earlier comments. It sounds like you guys are expecting LOE per barrel to climb here in 2Q and 3Q versus where you were in 1Q. I just wanted to make sure I heard that right.
No, we expected to go up to the midpoint of guidance from five bucks to midpoint of five to five fifty. So going up slightly due to third party water handling. Okay. And you're viewing that is somewhat temporary just based on where the rigs are going to be sort of be drilling, you know, location wise here. Okay.
Looking at first quarter, 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 taxes to kind of increase here in 2Q per the guidance.
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 maybe that just has to do with NOLs that are completely disappearing or other tax shield that disappears. But any other color around that cadence of cash taxes as the year progresses?
Yeah, I think the only real added benefit that Q1 had versus Q2, even if commodity prices were flat, is that we closed Lario.
in the quarter and got to, you know, right off some of that, the hard assets that came with that right away.
All right, so it sounds like it's just M&A driven on the tax shield side and now maybe QQ is more of a normal representative rate going forward.
All right, so it sounds like it's just M&A driven on the tax shield side and now maybe QQ is more of a Normal representative rate going forward. That's fair.
Okay, thank you. Thank you. One moment for our next question. Our final question comes from Paul Chang of Scoti Bank. Your line is now open. Thank you. Good morning. We're at Monday at Maya.
I want to add my appreciation with the new farmer. I think it's great. Two questions, please. First, you've been increasing your overall food activity in the midland over the last several years. So now you have 85-15% between the two. So we assume this is going to be pretty steady and stable for the next several years or that...
complete multi-well pads in the Delaware. So you know you have a quarter like Q1 of 2023 which was higher Delaware when Q4 was you know zero wells in the Delaware but on an annual basis 85-15 feels like the right lateral footage mix. Okay and the second question is that you talk about the subject you feel very comfortable.
budget or that, in other words, will that be a reasonable probability you're actually going to be below the midpoint of your budget and not? 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 and well costs and a little bit of the tail in from the activity of two rigs coming down. Now, I think that will happen a little bit in Q3 and more in Q4, but still early. Mm hmm.
Okay, can you share with us that, I mean, how much of the savings you already generally billion or how much is the decision in the second half that you have billion into your budget?
Okay, we saw more service cost deflation that would be upside to what we've modeled here.
Okay, we do. Thank you. Thank you.
This concludes our Q&A session. I would now like to turn it over to Travis Deiss, CEO , for closing remarks.
Thank you for joining us this morning. I think another benefit of this new format 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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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 speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1 1 on your telephone, and you will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1 1 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 Lawless, Vice President of Investor Relations. Please go ahead.
Thank you, Giro. Good morning and welcome to Diamondback Energy's first quarter 2023 conference call. During our call today we will reference an updated investor presentation in stockholder letter which can be found on Diamondback's website. Representing Diamondback today are Travis Deiss, chairman and CEO , Baseman, top president and CFO , and Danny Wesson 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 in businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC.
In addition, we will make reference to certain non-GAAP measures. The reconciliation with the appropriate GAAP measures can be found in our earnings release issued yesterday afternoon. I'm now turning the call over to Travis Suss. 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 improves efficiency. So we'll move right into questions. Operator, if you would open the line and begin with our first question.
Thank you. As a reminder, to ask a question, you will need to press star 1 1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1 1 again. Please stand by for our first question. Our first question comes from the line of Neil Dingham of Truist Securities. Your line is now open. First, thanks, Travis, for the new format. I appreciate it. Travis, my first question for you or Danny on one of the top abusers that service costs.
So, specifically, are you able to quantify how your continued operational efficiencies have recently mitigated your cost? And I'm just wondering how you all think about spot versus long-term contracts in the current environment. You know, I think, Neil, the reason to that question is, you know, kind of what the CapEx is going to look like in the back half of the year. Merkel tele ventura e Board of Trustees is a great post-COVID-19 200.
You know, I think there's, and I'll let Danny talk about the specific operational efficiencies we've seen here today that's offset most of the inflationary pressures, but when we talk about deflation, it's really, it's raw materials, it's diesel, it's sand, it's steel, particularly on steel because we're buying.
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.
And then lastly, while it's not necessarily a CAPEX issue, we're seeing improved efficiencies as we've got that second e-fleet that started last week. And we've also got rid of our two-spot frac crews and replaced them with one simul frac crew. That's all we have for you this evening.
you know, $10 to $20 a foot efficiency gains there as well. So regardless, Neil, of what's going on with CapEx, you know, our commitment has always been to be the low-cost leader, you know, when it comes to prosecuting our development plan out here. And we've got now almost a decade of demonstrating that. So we anticipate.