Callon Petroleum Company (NYSE:CPE) Q3 2023 Earnings Call Transcript

Callon Petroleum Company (NYSE:CPE) Q3 2023 Earnings Call Transcript November 2, 2023

Operator: Ladies and gentlemen, thank you for standing by. Welcome to Callon Petroleum’s Third Quarter Earnings Conference Call. [Operator Instructions] Just as a reminder, today’s conference call is being recorded. [Operator Instructions] I would now like to turn the call over to Callon’s CFO, Kevin Haggard. Please go ahead, sir.

Kevin Haggard: Thanks, operator, and good morning, everyone. Apologies. We had a little hiccup with the link to the webcast. I think we’re now all in, and there will be a recording afterwards. So we appreciate your interest in Callon. With me today are our CEO, Joe Gatto; and our COO, Russell Parker. We will happily take your questions at the end of our prepared remarks. We will reference our third quarter earnings release and supplemental slides, which are available on our website under the Investors tab. Today’s call will also include forward-looking statements that refer to estimates and plans. Actual results could differ materially due to risk factors noted in our presentation and SEC filings. We will also refer to some non-GAAP financial measures, which we believe help facilitate comparisons across periods and with our peers.

For any non-GAAP measures referenced, we provide a reconciliation to the nearest corresponding GAAP measure in the appendix to our slide deck and our earnings press release, both of which are available on our website. With that, I will now turn the call over to Joe.

Joe Gatto: Thank you, Kevin. Good morning, everyone. Cowen posted solid results for the third quarter, marking our 14th consecutive quarter of adjusted free cash flow generation, cash flow that we are using to reduce debt and repurchase our shares. Our corporate priorities are clear. We are focused on maximizing free cash flow, aggressively driving down our cost structure, reducing absolute debt and returning cash to owners through our share buyback program. I’ll divide today’s call into 3 segments. First, I’ll summarize third quarter financial and operating results. Overall, it was a good quarter with total production and key operating costs in line with expectations and capital investments below guidance. However, we did experience some headwinds related to our near-term oil production, which I will address shortly.

Second, I’ll cover our unrelenting focus on safely driving cost out of the system and creating sustainable operational efficiencies. Our focus on financial and operational cost controls is producing impressive gains, and we’ll pay increasing dividends into 2024 in terms of both free cash flow generation and lower breakeven prices for our Permian inventory. Next, I want to spend a bit of time on the sustainable benefits of our life of field co-development model. This is an ongoing and proven development process that maximizes the long-term value of inventory, where real-time learnings are then applied to future capital investments. We continue to see well productivity at Callon as moving counter to industry trends. However, we recognize that we need to continue to optimize that model over time with new information in order to properly balance near-term returns with longer-term opportunities.

Lastly, I will conclude with some early thoughts on 2024. Our recent efficiency gains in both drilling and completions are expected to be sustainable and will allow us to maximize value in 2024 through the enhancement of 2 key financial metrics, capital efficiency and free cash flow conversion of EBITDA. Let’s get started with third quarter results. For the third quarter, total production averaged 102,000 BOE per day. Oil sales averaged about 58,000 barrels per day. The shortfall in oil volumes is related to 2 key factors: first, the extreme temperatures and related power and midstream issues we experienced in July, which we discussed on the Q2 call, continued into August and September in the Delaware Basin, especially in our oil areas like Delaware East.

Power outages impacted our electrical submersible pump program and reduced expected order volumes due to downtime days as well as the time to ramp the ESPs back to normal operating levels. The second factor is related to oil production from recent multi-zone projects in the Delaware West, our most gas-weighted area. About 1/2 of our third quarter turn in lines or 15 of the 33 were in Delaware West. While total production on a BOE basis from recent completions was relatively in line with expectations, gas-to-oil ratios were much higher than expected. The commodity mix from these wells will also have an impact on our fourth quarter oil volumes. As an additional note, we recently accelerated a change in our Delaware Basin artificial lift program that was previously slated to start in 2024 to improve uptime performance.

This program will incorporate an increasing proportion of gas lift installs relative to ESPs over time to reduce production downtime from power and weather events, lower workover expense and enhanced longer-term resource recovery. In the fourth quarter, we do see some negative impact to production as compression-related equipment is procured and installed in areas where nearby gas lift installations don’t fully exist. With the program up and running this quarter and firmly incorporated into our planning process, we don’t expect to see this timing issue going forward. Overall, we expect fourth quarter oil production in the range of 56,000 to 59,000 barrels per day, with total production in the range of 100 to 103 BOE per day, comprised of approximately 79% liquids.

As part of our fourth quarter activity, we expect to turn 14 gross wells in line in the fourth quarter in our oilier areas, the Delaware East and Midland Basin, which will benefit our 2024 mix. Our forecasted capital investments for both full year and fourth quarter 2023 remain unchanged, despite an increase in drilling and completion activity driven by improving cycle times that I will hit upon in a minute. This clearly demonstrates the cost efficiencies we are realizing today. The corollary to the cost and capital efficiencies we are experiencing is that we are improving our rate of conversion of EBITDAX to adjusted free cash flow. In today’s deck, we show how this conversion has increased throughout the year. A few additional points to highlight.

G&A costs are now lower as a result of focusing the business solely on the Permian and streamlining our organizational structure. We are creating sustainable efficiencies across the business that will lead to improved results in future periods. We generated nearly $50 million in adjusted free cash flow this quarter. This gave us the flexibility to kick off our share repurchase program and opportunistically increase working interest in upcoming projects through several land initiatives. We are laser-focused on reducing absolute debt and strengthening our capital structure. At quarter end, total long-term debt was approximately $1.9 billion, down more than $300 million from the period — prior period. Our outlook for higher free cash flows in the fourth quarter will allow us to keep on pace with reducing debt and buying back additional stock through year-end.

We have benefited from recent acquisitions and are now a Permian-focused oil and gas company with scale. We added quality assets in the Permian and extended our runway of high-return long-lateral development locations. In terms of our recent Delaware acquisition, our first 5-well project is currently coming online, and we are encouraged by early time oil production rates and wellhead pressures. We will keep you updated on progress here. We have materially strengthened our balance sheet and implemented a cash return program for shareholders. We plan to use up to 40% of our adjusted free cash flow to repurchase shares in the fourth quarter. While we are focused on reducing absolute debt, we see buying back our shares at today’s valuation as a very attractive use of cash flow.

We have strengthened our leadership team and redesigned our operating teams. Our new COO, Russell Parker, is leaving no stone unturned as he assesses our business and benchmark our performance against industry. He is making an impact, applying has years of experience to safely enhance operational practices, lower costs and create sustainable synergies to drive future performance. I know it is eager to share some additional highlights and talk about his team some more during our Q&A. But as a start, early operational wins include: one, we are materially reducing days versus depth through the elimination of casing strings, which decreases cycle times and enhances project returns. Each of our developments going forward will have a fit-for-purpose casing design, tailored to maximize value.

We’ve provided a couple of examples of this on Page 7 of the presentation materials. Reductions in cost per lateral foot are being realized through the optimization of drill bits and the ability to drill long laterals. On the completion side, we’ve increased completed lateral feet per day by as much as 20%, and we’re seeing repeatable efficiencies and pumping rates and hours pumped per day. The combined impact of these realized improvements are driving overall performance into year-end. We now anticipate to complete approximately 50,000 more lateral feet and commenced drilling an incremental 5 wells relative to our midyear forecast. This additional activity will benefit 2024 production, all while staying within our existing budget. These accomplishments have been realized in a very short period of time after we’ve revamped our operations in recent months.

This has demanded a tremendous amount of effort, and I want to thank the entire organization for making this possible. Let me shift gears and discuss our life of field co-development model. This thoughtful approach to development has been constantly evolving over the past 5 years. It differentiates us from our peers and our well productivity is performing counter to industry. We have learned a great deal about interactions between our codeveloped zones and associated well spacing and placement. This continuous learning provides the foundation for ongoing tailoring of projects to maximize returns. For example, our recent co-development in our Delaware South area demonstrated that our deepest target zone could be developed separately over time, allowing us to reduce overall project sizes and cycle times as well as reduced facility investments.

This continuous improvement is critical to maximizing our NPV proposition. Let me wrap up today’s call by providing some of our early thoughts around 2024. Consistent with prior practice, look for formal guidance from us early next year. First, we will continue to focus on maximizing free cash flow. Our top cash flow priorities are to fund our high-value developments, reduce debt and repurchase shares. We believe that allocating capital appropriately across these buckets will drive improvements in our cost of capital. We will continue to be very disciplined with our capital investments. With recent efficiency gains in drilling, completion and facilities, we expect to do more with less in 2024 and forecast average DC&F cost per well to be down over 15% versus 2023.

In addition, ongoing high-grading of investments within our co-development model will allow us to target lower investment rates to enhance free cash flow. Our production trajectory in ‘24 will benefit from pulling forward more drilling and completion activity than initially planned as we are improving cycle times in the second half of this year as well as the return of a second completion crew early in the next year. In terms of our early thoughts on 2024 production outlook, increases in activity to drive top line growth will be secondary to drive an improved capital efficiency, as we prioritize debt reduction and share repurchases. I’ll also point out that we expect our oil mix to improve over the coming quarters as we focus on high-return oil areas in the Delaware and Midland Basins.

We will remain nimble as our 2024 program progresses, and we’ll evaluate increases in our activity to the extent we achieve DC&F reductions in excess of our original plan, similar to what we’ve done in the second half of this year. We appreciate your investment in our company, and we look forward to taking your questions. Operator?

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Q&A Session

Operator: [Operator Instructions] Our first question comes from Neal Dingmann with Truist Securities.

Neal Dingmann: Joe, my first question, maybe kind of get right to it, maybe for Russell. Just you talked about some 15% reductions and just really highlighting completion drilling, there’s just a lot of things. I’d love to hear straight from Russell just when he looks at ‘24, where he thinks a lot of these savings potentially could come from?

Russell Parker: And I appreciate the question. And actually, we already started to see some of this come to fruition as we modify our casing strength. It’s going to be a different mix of savings across the portfolio, probably the way it will shake out, we take 15% plus on average per well DC&F. And the way that breaks out, it’s about a 15% on average savings on the drilling side, about a 5% average on the completion side and about 50% savings on facilities. And really, what that all boils down as a little bit of cost of services. There is a little bit of that single digits, 3% to 5%, depending upon which input you’re talking about. But really, the big change is coming from shifting from kind of a standard mindset, a standard way of doing things to a fit for purpose.

So we’re looking at each individual location and looking at where we can reduce casing streams, reduce hole sizes, run our bit program and our bit life much longer than what we have been potentially drilling with conventional tools instead of rotary steerables. And in some places, we actually save money doing that and we can keep the tools in the whole longer. And then on the facility — on the completion side, a lot of that savings is coming from sand. That’s not unique to Callon. Now some of the logistics is — are unique to Callon. That’s the bulk of where we see that savings coming from. We think we could probably stretch a little bit further on the completion side even as we go into 2024, and that will be our goal. As we look to increase our pump rates, potentially complete 2 pads at the same time.

We’re throwing a lot of ideas out there. We’re going to let the team really stretch their legs, really kind of push the envelope of engineering excellence to help reduce those costs. And then on the facility side, it’s really, once again, it’s fit for purpose. So we’ve spent a good deal of money over the years with our life of field model, building up an infrastructure of equipment and flow lines and tank batteries, what have you. We’re pulling out of the point where we can actually, one, start harvesting less of that equipment, but two, also look at maybe building our on-pad facilities a little bit differently, using more [bulk lines] and trunk lines, integrating gas lift systems that while it takes a little time to get together, actually, over time, will save us money.

So it’s a large combination of the projects. If you had about 4 hours, I’d love to take you through all of it, but we don’t have that kind of time today, but — and a whole lot of folks working on it. But basically, that fit-for-purpose design versus just taking a standard.

Neal Dingmann: Great details, Russ. And then definitely will take you up on that and love your more sometime offline. And then Joe, my second question is just on capital allocation. I’m just wondering what would be the primary drivers or what is the primary drivers would you and Kevin decide that now on a go forward lean into the buybacks versus allocate a bit more on the growth side?

Joe Gatto: Yes. Look, we’ve talked about the 3 buckets that we have in terms of adding value, clearly investing in the asset base in a disciplined way, the first stop. But we are very focused on debt reduction, we put goals out there. We’re serious about getting to them and also following through on our share repurchase program. So we have a lot of efficiencies that Russell’s talked about here, not only from a cost perspective, but also from cycle times, but we are going to be cognizant. We don’t want those efficiencies to drag us to higher reinvestment rates. So by focusing on high-grading our opportunity set going forward, we can find a nice balance in between there to deliver high-return projects, keep our reinvestment rates in check, have more free cash flow to deliver to incremental debt reduction and share repurchases.

Operator: Our next question comes from Zach Parham with JPMorgan.

Zach Parham: First, could you give us a little more color on what you’re seeing from those gassier wells in the Delaware West area? Maybe add some thoughts on how you think about future development in that area? Do these well results change kind of how you think about your inventory that you have remaining over there?

Russell Parker: Sure. I’ll take that question. The Delaware West particularly has been our gassiest part of our portfolio. That’s nothing new. That’s no real surprise. The good news is we have a lot of places to invest money going forward too. So as Joe has alluded to, we’re going to look at, one, how we’re designing, spacing, completing, landing and developing the property with a lower cost structure going forward in order to continue to maximize value. And then also in the near term, our other assets, the East and the Midland Basin, obviously, will help pull up that oil mix as we’re going forward.

Joe Gatto: And I think specifically on the Delaware West project, we said we had a lot higher GOR ratios than we expected. I think some of that is attributed to — look, it’s an active area around us over time. So some of that activity most likely led to some depletion effects in that area. But there are lessons learned from that project going forward. We still think Delaware West is an attractive area. But with co-developments that we’ve got to evolve over time. So we’re probably putting a few more less — or sorry, a few less sticks in the deeper zones in the Wolfcamp B and C would be one thing that we take away from that. But overall, Delaware Western area will be back to over time. Part of our program with scale development is to rotate our projects, because we’re not overtaxing infrastructure, leverage the infrastructure we have in place, and there’s very similar returns across the portfolio for different reasons.

But hopefully, that gives you a sense of where we’re heading from Delaware West, but there’s certainly some takeaways there that we’re incorporating in our designs going forward.

Zach Parham: Got it. And then maybe just following up on Neal’s question. You’ve talked a lot about cost reductions on DCF. Can you give us any sense of what 2024 CapEx might look like if costs play out the way that you think they will? Should we be thinking about a similar number of turn in lines next year and CapEx is just simply 15% lower year-over-year? Or is it more complicated than that?

Joe Gatto: Yes, Zach, we wanted to give you the building blocks here, certainly around DCF average well costs. But I said the cycle time element is really critical here in terms of how we plan out for next year. Obviously, we have a good pathway into the beginning of the year with getting a jump start on activity into the first quarter from the savings we’ve had in ‘23. But yes, it is more complicated than just taking down 15%. We do want to be mindful, as I said, around reinvestment rates. We could — with everything that we’ve shown in recent months on the drilling side and completion side, that allows us to go faster in general. But we’re going to moderate our investments appropriately to balance all of our free cash flow objectives.

So we’ll be able to fill in the holes here in the next couple of months, but certainly, I wanted to give you some of the building blocks going into next year, again, being lower DC&F per well, improved cycle times and a good trajectory going into the beginning of Q4 with some oil-weighted projects.

Operator: Our next question comes from Oliver Huang with TPH.

Oliver Huang: Joe, Kevin and Russell. Certainly, good to see the incremental detail around a lot of the cost initiatives that you all been working around and I mean, 15% is certainly a meaningful number. But maybe just kind of a follow-up to Neal’s earlier question. How immediate are these savings? Is that something that we’d expect to start in full force at the beginning of 2024? I know you all have already made headway on that to date. Or is that something that we should expect to kind of layer in a bit more gradually?

Russell Parker: It’s already happening now. And I’d say, as we get into Q1, we should be in the neighborhood of already realizing that, hopefully, definitely averaging us through the year, maybe even beating it as the year goes on, depending — of course, depends on where commodity prices and service rates are. But to that point, and Joe mentioned it earlier, we’ve got extra projects that we’re actually drilling and completing this year, about 50,000 extra lateral feet, another handful of wells that we’re going to spud in ‘23 that were not in our anticipated budget at midyear. These projects are going to add production in Q4. So obviously, Q1, you won’t see them in Q4, adding production next year. But we’re able to do that and still stay within our original budget.

And the reason is we’re already starting to realize some of these cost saves. I don’t think we’re not quite to the 15% range yet, maybe single digits, because obviously one of the biggest cost savings, which is going to take time to layer into that facility piece. That one is going to be more Q2, 3, 4. But the par on the D and the C side, where we’re already starting to see, come to fruition now, actually.

Oliver Huang: Awesome. That’s helpful. And maybe another follow-up just with respect to the facility side. Would such a change, that you all are kind of talking about, impact the expected production trajectory of well productivity? Is it more so along the lines of just kind of constraining IPs a little bit more to avoid overbuilding of the facilities? Or is it more so along the lines of just kind of using stuff that’s already existing?

Russell Parker: It’s using things that are existing, in some places, yes, you might actually see a lower IP30 but similar IP90. That’s part of the ways in which we’re saving some money. If you build everything for an IP30, your cost structure is higher. However, if you look at your rate of return, it’s better building towards an IP90. So over the year, you wouldn’t see it maybe on an exact well in an exact month, you might see a different peak. But if you were looking at a quarter of publicly available data, no, I don’t think you’d see the difference and you’d probably see more stable production over time. The other place — in some places, some of the design changes we’re talking about will actually help eliminate or reduce back pressure, which will actually improve — potentially improve some of our production on the base.

Oliver Huang: Awesome. And if I could squeeze just one more in with respect to the Q4 guide. Obviously, a downward revision there. But just wanted to see, is there any sort of breakout in terms of what could be attributed to the less oil than expected from the subset of wells that came out of the West area within the quarter versus just incremental downtime from accelerating some of the optimization that you’re doing on the artificial lift side?

Joe Gatto: Yes. The large majority will be from what we highlighted at Delaware West.

Operator: Our next question comes from Derrick Whitfield with Stifel.

Derrick Whitfield: Congrats on the structural improvements you’ve outlined this quarter.

Joe Gatto: Thanks, Derrick.

Derrick Whitfield: Starting with a follow-up on the Delaware West development. I wanted to ask if you could lean in on the learn lessons? And specifically, does the higher GOR indicate greater vertical connectivity to the lower Wolfcamp zones or simply a gassier upper Wolfcamp based on past depletion from [indiscernible] development?

Russell Parker: So I’d say that the generic learning is you’ve got to make sure you’re doing a great job, taking into account not what happen on your acreage, but offset acreage. We’re projecting that into the future, looking at how that regional depletion may impact you going forward. And then also looking at how your spacing needs to be appropriately designed or redesigned in order to optimize your capital investment going forward. There’s still plenty to do there. But yes, a lot of what it may involve is in order to maximize NAV, because you’re dealing with a little bit lower reservoir pressure as we’re talking about wells with larger completions, specifically space further apart, actually optimizes your NAV when you’re seeing that.

But that’s really, I’d say, the key learning from this is looking at bench-by-bench, what is the appropriate spacing, looking bench-by-bench to see which wells are communicating with what, where you have local geologic features, where you have localized increased depletion from offset operators to make sure that you’re optimizing your capital going forward.

Derrick Whitfield: And Russell, kind of looking forward with that development in that area, do you think you’ll have enough data kind of post this set, post assessment to have a good feel for what spacing should be as you guys look to develop that out in 2024 and 2025.

Russell Parker: Absolutely. Well, not only are we looking at fit for purpose on the DC&F side, but we’ve actually really started to unlock some of the other team members as we change our structure and really take into account and analyze quite a bit more data than we have in the past as a company. We’re actually doing a lot of exciting things around machine learning and predictions and reservoir simulation to help us improve the accuracy of our models and really have a good handle on how you can iterate on different spacing, different landing, which how many individual wells and what completion time it takes to optimize NAV per bench, which business we see are communicating with one another. We’ve been doing some exciting experiments actually to figure out fluid typing and actually being able to really see what zones are communicating with what other zones by doing what’s called like a fluid fingerprint.

So absolutely, it’s an incredible focus of our technical team, not only in this space, but everywhere, because the same learning — or the same process can be used to help you optimize your NAV all your assets.

Derrick Whitfield: I’m going to work on your side. One final, if I could, just on Page 8. Looking out into 2024, could you speak to how impactful 3-mile lateral development could be in your operational plan?

Russell Parker: Sorry, you said, how impactful 3-mile lateral.

Derrick Whitfield: Correct. Yes.

Russell Parker: Yes. Well, part of what we wanted to show there was actually not only just record lateral, but record time, which the first time saves money. In terms of how many locations we’ll have next year, that will be 3 miles, but we’re still working on our budget and figuring that out. I’d say probably the P50 answers that we’re still drilling 350, 10,000-foot wells. But we are looking for places where we could extend that wherever possible. As matter of fact in one particular location, we couldn’t even drill a straight 15,000-foot hole. So we — but we drilled basically, if you will, like an L-shape well almost or well with a bend in it in order to, one, optimize depletion of the reservoir dealing with these situations that we had, the acreage situation that we had, our footprint, but also thereby maximizing our returns.

So we’re going to be looking at that. We’re going to be looking at U-shaped wells. We’re going to look at a lot of different concepts in order to optimize our NAV but also kind of opening our lines to all within the art of the possible in terms of well shape, landing, length and time to depth.

Operator: Our next question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold: And hopefully, this hasn’t been asked yet. I’ve been just jumping around to a couple of calls that are going on. But just in terms of what you all saw in the Delaware West and what you’re learning there. Can you talk about like your asset base just more at large? Is there other areas that have regional [position] or spacing that is something you’ll be cognizant of? Or is this — is this more Delaware West specific? And can you talk about where Delaware West fits into your, like, overall inventory and activity levels moving forward?

Russell Parker: So I’d say, going forward into next year, I see we’re probably going to be more heavily weighted in the East and in the Midland Basin. However, we do already have some slated projects in South and West. And honestly, you can map this, we’ve actually made some cool little movies about it, little videos. Regional pressure decline is real in all benches within the Permian. If anybody tells you that it’s not, then they’re not looking at the data. That doesn’t mean you can’t make money, however. That just means you got to take it into account when you’re building your development plans and as you continue to learn and modify your development plans. So I think, look, the process and what we learned in the Delaware West is something that you can apply everywhere.

Do you see that same level of pressure decline all throughout the Permian, no, it’s specific by bench, it’s specific by area depth, which portion of the country that you’re in. So it’s not a blanket answer, which again is why I kind of come back to when you’re developing your asset, the same thing for Callon. You want to do a fit-for-purpose design, because not each area is seeing a similar phenomenon, but not at the same level ought the same degree, not the same — not at the same with every bench, right? You don’t see it, because maybe the reservoirs that start out with the same in-situ GOR and start out with the same historical — our geologic history and diagenesis. So there’s all sorts of reasons that produce different results, but the process and the learnings we can apply everywhere.

In terms of, yes, where I see us spending money or where we see ourselves spending money, definitely a lot of — probably more weighted to the Delaware East and Midland asset in ‘24. We do still have projects still in the South and in the West and then we’re working on some things longer term to make the investment opportunity even more exciting in those basins, those part of our assets, but more to come on that. That’s the teaser for next year.

Scott Hanold: Okay. More specifically to that answer then, and you talked about that everything is kind of a region specific to a certain extent, and you got to fit to design to that area. Do you all feel you have a pretty good handle on that moving forward? Or is there still some learning — is 2024 is still going to be a partial learning year? Or do you feel good about where you’re entering the year and setting those expectations?

Russell Parker: Well, one, we feel good about where we are. But two, I think you’re always learning. We should learn on each and every path. So I wouldn’t say we’ve never stopped learning and never expect to stop learning or modifying, tweaking and improving. If the organization does that, you kind of dial in — you dial in on the line. But no, I think we feel good about where we are, where our current set of expectations are. We feel good about what we’ve learned. And then all that said, from here, we look to try to improve and improve and improve. And again, you never — and actually, this is a new focus on the team. We review each completion at the time of [AAP]. We reviewed each completion 2 weeks before we actually complete it [indiscernible].

And with each pad, each field where each business unit is working on little tweaks, little design implement, little things that we’re learning from ourselves, from offset operators that will notch out another 3%, 4% rate of return. Just like when it was in the slide deck you saw, there were couple of little things you could do, add 3, 4%, 5%, 6%, 7%, 8%. Well, same thing happens with completion design. Same thing happens with [indiscernible] landing and spacing. Same thing happens with your role texture cost structure. And all of a sudden, you take inventory that might have been 20% rate of return, you’re making at 40% or 50%. It takes a lot of effort to get you there, but that’s going to be an ongoing process. But I’d say generally, we feel good about where we are, but I don’t expect us to stop learning, we should always keep learning and always keep modifying.

Scott Hanold: Understood. And Joe, this one might be for you. I mean, obviously, you guys are very focused on getting the operations where they need to be, getting the cost down. I mean that’s obviously priority #1, but certainly, consolidation has become extremely topical here over the last few months. You guys have — yourselves have been involved in it for a number of years as well. Can you talk about the thoughts on Callon and where it’s on sort of consolidation where you’d like to see the company over the next few years?

Joe Gatto: Yes, Scott, I’ll hit that at a high level. I mean, obviously, we’ve seen a lot of consolidation of assets and some corporate activity out there. That shouldn’t be all that surprising anyone who’s been around this business that happens over time, not only as people pursue inventory. But with this latest iteration, obviously, cost of capital for this industry has gone up and largely speaking, bigger companies are afforded a better cost of capital. So we’re laser-focused on what’s happening around us. And as we said, we’ve actively participated in that in shapes and forms over time. I think we have to be nimble and make sure that we’re positioned to participate in the right way consolidation and that boils down to 2 things. One is having a robust inventory, the strong economics, which we have and a good balance sheet that’s improving, which we have. And that gives you options across the spectrum moving forward.

Operator: Our next question comes from Paul Diamond with Citi.

Paul Diamond: A couple of quick ones for me. In the prepared remarks, you guys talked about some learnings around deeper zone being able to be developed separately from other benches. Just wondering if you can provide a bit more color there?

Russell Parker: We did an experiment earlier this year in which we fingerprinted, if you will, the fluid from a bunch of — from all the different benches. And then we use that fingerprint along with several fluid samples in each of the wells in each bench that we took over time, to see which wells we’re communicating with which wells over time. And it was very interesting, you’d see a different mix of communication from early in life to late life. But from that process, we could figure out which benches basically we’re not communicating, which our outpart apart the well needs to be in which you really didn’t see that communication, if not early time, but over the long term, meaning you have the opportunity to potentially develop those benches at a later date.

So it’s through a process of fluid fingerprinting quite detailed, and there’s a couple of different companies that specialize in this, but that’s how we’ve done it. And we’re applicable, we may be — a few more experiments where we get that kind of data again to help us better understand exactly what reservoirs are communicating with what reservoirs and of which pattern, because it also — the order in which you develop the reservoirs will impact that, whether not you’re drilling upper wells versus lower wells or lower well or suffer wells and which order they come in over time. So — but that’s how we did it. It was a fluid fingerprinting experiment.

Paul Diamond: Understood. Were there any geographic areas that was more focused in? Or is it pretty much the entire Permian?

Russell Parker: That particular experiment I’m referring to was in the South, but we may look at doing some similar experiments elsewhere in our acreage in ‘24.

Paul Diamond: Understood. Just one quick follow-up. On Slide 8, you had some pretty interesting kind of trend data on spud to rig release, competitive laterals and D&C per lateral. Just wanted to get an idea of how you guys are viewing as those trends going forward into ‘24 and beyond? Should we assume somewhat linear or diminishing returns or just how you guys are thinking about that?

Russell Parker: I think you’ll see — it will be a [indiscernible] for sure. We’re already realizing some of it. We’re not to the end of the [indiscernible] at all yet, I’d say. But with any program like this, as you look to make tweaks and look to make tweaks, kind of you hit your lowest-hanging fruit early, which may be say casing streams when we talk about well design, and then the more difficult tweaks come later, exact [indiscernible] program, exact-fit program, all the other little pieces that will save time off, but maybe not as dramatically as say, eliminating a casing stream. So I’d say we’ll never stop trying. But obviously, in any design change, you always see the lowest hanging fruit first, which means you get your biggest impact first.

That’s why I said, I think we’re already probably in that 10% savings range and end of the Q4, beginning Q1, looking at average 15% or better over the year. But as the year goes on, continue to tweak that and tweak, tweak that and tweak our science to find a little bit more. But yes, if you were to draw it out, it looks like an [asset], but you — at the same time, if you are open-minded and fit for purpose, you’ll always find something.

Operator: Our next question comes from Gabe Daoud with Cowen and Company.

Gabe Daoud: I was hoping, Joe, you could just go back to the comment around lower reinvestment rates. And I know you mentioned the goal of that is to better manage free cash initiatives. But just curious, how does that translate to top line growth? I think previously, you guys had mentioned maybe a 0% to 4% growth rate on production on an annual basis. So just curious then how does lower reinvestment rate equate to that number? I’m assuming maybe it’s lower over time, but just curious to hear your thoughts.

Joe Gatto: Yes, Gabe, Happy to take that. What I mentioned earlier going into ‘24, the priority is really going to be on capital efficiency and realizing all the things we’ve been talking here about in terms of DC&F costs, high-grading our asset base, improving cycle times. I think that will get us off to a good start, getting into ‘24. We’ll obviously provide some more formal guidance as we move forward. But in the near term, we are prioritizing capital efficiency and cash flow versus any meaningful headline production growth. Now hopefully, we realize all these efficiencies, get going, hoping to do better. I think that’s the time we look at adding some additional activity with reinvesting back in the asset base over time, but give us some time here to put all these things in motion.

Gabe Daoud: Okay. Understood. And then I guess as a follow-up, you highlighted a lot of the, obviously, cost savings on the capital front. But just curious, you did another good job here on LOE. How does LOE trends into ‘24? And do you think there’s more you could squeeze out of there?

Russell Parker: I think our biggest opportunity on LOE long term is fixing our failure rate. Our failure — ESPs account for about 5 days of our artificial lift — that’s where our highest value rate is. And that’s probably the high — the largest part of our expense structure, I’d say on the LOE front that has the opportunity — some opportunity for improvement. That won’t happen quickly. You don’t change failure rate overnight or even in a quarter. That comes from a program change not only a fit-for-purpose artificial lift, but how you’re optimizing the ESPs, what size they are, a whole host of what your surface facilities do in terms of maintaining electric power even when you’re suffering power outages. So there’s a whole host of things that you have to do there in order to improve that failure rate.

But that portion of our spend is neighborhood $50 million a year. And it’s all driven by the rate at which wells fail. So it will be a big focus of ours in ‘24 to try to waddle that down and see if over the next couple of years, we can’t cut that in half or reduce it by 75%, ideally in time. But that’s probably the biggest single opportunity. Otherwise, what we’re looking at structurally are some places in which we can improve our — not only basically improve our chemical spend with some larger infrastructure projects that’s going to take some time to implement. And of course, that’s because we deal with sour gas, just like a lot of other people do in the Delaware Basin. I got a little bit of the Midland Basin, but not as prolific there.

But I’d say those 2 areas are going to be our primary focuses on LOE. But don’t take — those will probably take longer to come to fruition.

Operator: There are no further questions at this time. I will now turn the call back to Joe Gatto for any closing remarks.

Joe Gatto: Thank you, everyone, for joining and the interest in Callon. We covered a lot of ground here today with a lot of exciting things going on. We’ll have a lot more to fill in over the coming months and look forward to keeping you all up to date on that. And as always, with any questions, please be able to reach out. Thanks again.

Operator: This concludes today’s conference call. Thank you for joining us. You may now disconnect.