Ladies and gentlemen, thank you for standing by. Welcome to Callon Petroleum's Third Quarter Earnings Conference Call. All participants are now in listen-only mode. After the prepared remarks, there will be a question-and-answer session. Please note that each caller will be limited to one question and one follow-up question. Just as a reminder, today's conference call is being recorded. If you would like to join the queue for questions, please press star one on your telephone keypad. To withdraw your question, please press star one again. I would now like to turn the call over to Callon CFO, Kevin Haggard. Please go ahead, sir. 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, 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. Thank you, Kevin. Good morning, everyone. Callon posted solid results for the third quarter, marking our fourteenth consecutive quarter of adjusted free cash flow generation. Cash flow that we, 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 three 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 well, I will address shortly. Second, I'll cover our unrelenting focus on safely driving costs out of the system and creating sustainable operational efficiencies. Our focus on financial and operational cost controls is producing impressive gains and will pay increasing dividends into 2024 in terms of both free cash flow generation and lower break-even 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 two 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 two 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 oilier areas like Delaware East. Power outages impacted our electrical submersible pump program and reduced expected oil 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 one half 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-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 enhance 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 currently 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 a range of 56-59 thousand barrels per day, with total production in a range of 100-103 barrels 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 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 five-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've 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 benchmarks our performance against industry. He's making an impact, applying his years of experience to safely enhance operational practices, lower costs, and create sustainable synergies to drive future performance. I know he 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 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 in 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 commence drilling an incremental five wells relative to our mid-year 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 five 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 co-developed zones and associated well spacing and placement. This continuous learning provides a foundation for ongoing tailoring of projects to maximize returns. For example, a 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 reduce 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 costs 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 2024 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 driving 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 oily 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? Thank you. We will now open the line for questions. As a reminder, to ask a question, please press star one. Our first question comes from Neal Dingmann with Truist Securities. Your line is open. Morning, all. Thanks for the time. Joe, my first question, maybe kind of get right to it, to maybe for Russell. Just you talked about some 15% reductions and just, you know, really highlighting completion drilling. There's just a lot of things I'd love to hear, straight from Russell, just, you know, when he looks at 2024, where he thinks a lot of these savings potentially could come from. Hey, morning, Neal. I appreciate the question, and actually, we're already starting to see some of this come to fruition as we modify our casing strings. It's gonna be a different mix of savings across the portfolio. Probably the way it'll shake out, we think 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 to is a little bit of cost of services. There is a little bit of that, single digits, you know, 3%-5%, depending upon which, which input you're talking about. But really, the big change is coming from shifting from a 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 strings, 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 steerable. And in some places, we actually save money doing that and can keep the tools in the hole 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, though, some of the logistics are unique to Callon. That's, but 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'll 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 gonna 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, 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 going now to the point where we can actually, one, start harvesting a bunch of that equipment, but two, also look at maybe building our back, building our on-pad facilities a little bit differently, using more bulk lines, trunk lines, integrating, gas lift systems that, you know, while it takes a little time to get together, actually, over time will save us, save us money. So it's a, it's a large combination of projects. You know, if you had about four hours, I'd love to take you through all of it, but we don't have that kind of time today. But a whole lot of folks working on it, but basically, it's that fit for purpose design versus just making a standard. Great details, Russell. And then, definitely we'll take you up on that. I'd love to hear more sometime offline. And then, Joe, my second question, just on cap allocation. I'm just wondering, what would be the primary drivers, or what is the primary drivers when you and Kevin decide that, you know, now on a go-forward, lean into the buybacks versus allocate a bit more on the growth side? Thanks. Yeah, you know, look, you know, we've talked about the three buckets that we have in terms of adding value. Clearly, investing in the asset base in a disciplined way is 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 purchase 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 gonna 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. Thank you, guys. Our next question comes from Zach Parham with JP Morgan. Your line is open. Hey, guys. Thanks for taking my question. First, could you give us a little more color on what you're seeing from those gassier wells in the Delaware West area? You know, 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? Sure. I'll take that question. You know, the Delaware West classically 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 to. So Joe was alluding to, you know, we're gonna look at, one, how we're, 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, you know, our other assets, the East and the, and the Midland Basin obviously will help pull up that oil mix as we're going forward. I think specifically on, you know, the Delaware West project, as you said, we had a lot higher GOR ratios than we expected. I think some of that is attributed to, it's an active area around us over time. So some of that offset activity most likely led to some depletion effects in that area. But, you know, there are lessons learned from that project going forward. We still think Delaware West is an attractive area, but with co-development, so we got to evolve over time. So, we probably put in a few more less, or sorry, a few less sticks in the deeper zones in the Wolfcamp B and C, would be, you know, one thing that we take away from that. But overall, you know, Delaware West area, we'll be back to over time. You know, part of our program with scale development is to rotate our projects. We're not overtaxing infrastructure, leveraging infrastructure we have in place, and there's very similar returns across the portfolio for different reasons. But, you know, 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. Got it. And then maybe just following up on Neal question. You know, y'all talked a lot about cost reductions on DC&F. Can you give us any sense of what 2024 CapEx might look like if costs play out the way that you think they will? You know, 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? Yeah, Zach, you know, we wanted to give you the building blocks here, certainly around DC&F, average well cost. But I said, you know, 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 2023. But yeah, it is more complicated than just taking down 15%. You know, we do wanna be mindful, as I said, on around reinvestment rates. We could. With everything that we've shown in recent months on the drilling side and completion side, you know, that allows us to go faster in general. But, we're gonna 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, you know, certainly 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. Got it. Thanks, Joe. Thank you. Our next question comes from Oliver Huang with TPH. Your line is open. Good morning, Joe, Kevin, and Russell. Oliver. 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 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, on that, to date, or is that something that we should expect to kind of layer in a bit more gradually? It's already happening now, and I'd say as we get into, you know, Q1, we should be in the neighborhood of already realizing that, hopefully, definitely averaging it through the year, maybe even beating it as the year goes on, depending, of course, on where commodity prices and service rates are. But to that point, and Joe mentioned it earlier, we've got, you know, extra projects that we're actually co-drilling and completing this year, about 50,000 extra lateral feet. You know, another handful of wells that we're gonna spud in 2023, that were not in our anticipated budget at mid-year. These projects are gonna 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 savings. I don't think we're at a- We're not quite to the 15% range yet, maybe single digits, because the, obviously, one of the, the biggest cost savings, which is gonna take time to layer in, is that facilities fee. That one's gonna, you know, be more Q2, three, four, but the part on the D and the C side, we're, we're already starting to see, come to fruition, now, actually. Awesome, that's helpful. Maybe another follow-up, just with respect to the facilities 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? It's using things that are already existing. In some places, yes, you might actually see a lower IP30, but a similar IP90. That's part of the ways in which we're saving, saving some money is, if you build everything for an IP30, your, your cost structure is higher. However, if you look at your rate of return, it's, 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, you know, and if you were looking at a quarter of, 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. Awesome. 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 some incremental downtime from accelerating some of the optimization that you're doing on the artificial lift side? Yeah, the large majority would be from what we highlighted, Delaware West. Okay. Thanks. Appreciate the color, guys. Our next question comes from Derrick Whitfield with Stifel. Your line is open. Thanks, good morning, all, and congrats on the structural improvements you've outlined this quarter. Thanks, Derrick Starting with a follow-up on the Delaware West development, wanted to ask if you could lean in on the learned lessons, and specifically, does the higher GOR indicate greater vertical connectivity through the lower Wolfcamp zones, or simply a gassier upper Wolfcamp based on past depletion from Bone Spring development? So I'd say that the generic learning is you gotta make sure you're doing a great job of taking into account not what only happened on your acres, but offset acres. 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. So 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, is we're talking about, you know, wells with larger completions potentially spaced further apart, actually optimizes your NAV when you're seeing that. But that's really the. 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, your capital going forward. And Russell, kinda looking forward with that development in that area, do you think you'll have enough data kinda 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? Absolutely. Well, not only are we looking at fit for purpose on the DC&F side, but we're, 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, how many individual wells and what completion design it takes to optimize NAV per bench. Which benches 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, no, absolutely, it's an incredible focus of our technical team, not only in this basin, but everywhere. Because the same learning or the same process can be used to help you optimize your NAV on all your assets. Phenomenal work on your side. One final, if I could, just on page 8. Looking out into 2024, could you speak to how impactful three-mile lateral development could be in your operational plan? I'm sorry, you said how impactful 3-mile lateral? Correct. Yeah. Part of what we wanted to show there was actually not only just record lateral, but record time, which, of course, time saves money. In terms of how many locations we'll have next year, that'll be three miles, but we're still working out our budget and figuring that out. I'd say probably the P50 answer is that we're still drilling, you know, P50 10,000-foot wells, but we are looking for places where we can extend that wherever possible. Matter of fact, in one particular location, we couldn't even drill a straight 15,000-foot hole. So we- but we drilled basically a, if you will, like, an L-shaped well, almost, or a well with a, like a bend in it, in order to, one, optimize depletion of the reservoir, dealing with the lease situation that we had, the acreage situation that we had, our footprint, but also, thereby maximizing our return. So we're gonna be looking at that. We're gonna be looking at U-shaped wells. We're gonna look at a lot of different concepts in order to optimize our NAV, but also kinda, opening our minds to all, what's within the art of the possible in terms of well shapes, landing, lengths, and time to depth. That's a great update. Thanks for your time. Thank you. Our next question comes from Scott Hanold with RBC Capital Markets. Your line is open. Hey, thank you all. 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, you know, what you all saw in the Delaware West and what you're learning there, you know, can you talk about, like, your asset base, just more at large? You know, is there other areas that have, you know, regional depletion or spacing that there's something you ought to be cognizant of, or is this one of- 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? So I'd say going forward in the next year, I see we're probably gonna be more heavily weighted in the east and in the Midland Basin. However, we do already have some slated projects in south and west. 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 gotta 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 parts of the county that you're in. So it's not a, it's not a blanket answer, which, again, is what I kinda come back to when you're developing your assets, the same thing for Callon. You wanna do a fit-for-purpose design because not each... Each area is seeing similar phenomenon, but not at the same level, not the same degree, not the same-... not with the same with every bench, right? You don't see, you don't see it because maybe the reservoirs didn't start out with the same, in situ GOR, didn't start out with the same, you know, historical, or 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, yeah, 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 2024. We do still have projects in the south and in the west, and then we're working on some things, longer term that 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. Okay, the more specifically to that answer then, you know, and, and you talked about that it's, it, you know, everything's kind of region specific to a certain extent, and you got to, you know, fit the design to, you know, to that area. Do you, do you all feel you have a pretty good handle on that moving forward, or is there still some learnings? Is, is 2024 still gonna be a partial learning year, or do you feel good about where you're entering the year and, and, you know, setting those expectations? Well, one, we feel good about where we are. But two, I think you're always learning. You should learn on each and every pad. 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 kinda die on the vine. 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. Yeah. And actually, this is a new focus on the team. We review each completion at the time of AFE. We review each completion two weeks before we actually complete it to see if we wanna tweak anything. And with each pad, each field, each business unit is working on little tweaks, little design implements, little things that we're learning from ourselves, from offset operators, that, you know, will notch out another 3%-4% rate of return. Just like what was in the slide deck you saw, you know, there's a couple of little things we could do, add 3, 4, 5, 6, 7, 8%. Well, same thing happens with completion design, same thing happens with little tweaks to landing and spacing. Same thing happens with your little tweaks to your cost structure, and all of a sudden, you take, you know, inventory that might have been 20% rate of return, you're making it 40 or 50. It takes a lot of effort to get you there, but that's gonna be an ongoing process. But I'd say, Joe, we feel good about where we are, but don't expect us to stop learning. We should always keep learning and always keep modifying. Understood. And Joe, this one might be for you. I mean, you know, obviously, you guys are very focused on getting the operations where they need to be, getting the costs down. I mean, that's obviously, you know, priority number one, but, you know, certainly, you know, consolidation has become extremely topical here over the last, you know, few months. You guys have, yourselves have, you know, been involved in it, you know, for a number of years as well. Can you talk about the thoughts on, you know, Callon and where it fits on sort of consolidation, where you'd like to see the company, you know, over the next few years? Yeah, 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 to 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, you know, bigger companies are afforded a better cost of capital. So you know, we're laser focused on what's happening around us, and as you said, we've actively participated in that in shapes and forms over time. I think, you know, we have to be nimble and make sure that we're positioned to participate in the right way in consolidation, and that boils down to two things. One is having a robust inventory, a 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. Thank you. Our next question comes from Paul Diamond with Citi. Your line is open. Hi, good morning, all, and thanks for taking my call. A couple quick ones from me. In the prepared remarks, you guys talked about, you know, some learnings around deeper zones being able to be developed separately from other benches. Just wondering if you could provide a bit more color there. We did an experiment earlier this year in which we fingerprinted, if you will, the fluid from all the different benches. And then we used that fingerprint along with several fluid samples in each of the wells, in each bench, that we took over time to see which wells were communicating with which wells over time, and it was very interesting. You'd see a different mix of communication from early in life until late in life. But from that process, we could figure out which benches basically were not communicating, or how far apart the wells need to be, and 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 where applicable, we may do a few more experiments where we gather that kind of data again to help us better understand exactly what reservoirs are communicating with what reservoirs and in which pattern. Because it also. The order in which you develop the reservoirs will impact that. You know, whether you're drilling upper wells versus lower wells or lower wells versus upper wells and which order they come in over time. So but that's how we did it. It was a fluid fingerprinting experiment. Understood. Were there any geographic areas that was more focused in, or is it pretty much the entire Permian? That particular experiment I'm referring to is in the south, but we may look at doing some similar experiments elsewhere in our acreage, in 2024. Understood. Thanks. Just one quick follow-up. On slide 8, you had some pretty interesting kind of trend data on, you know, spud to rig release, completed laterals, and D&C per lateral. Just want to get an idea of how you guys are viewing those trends going forward into 2024 and beyond. Should we assume, you know, somewhat linear or the diminishing returns, or just how you guys are thinking about that? I think you'll see, so it'll be an asymptote for sure. You know, we're already realizing some of it. We're not to the end of the asymptote at all, yet, I'd say. But with any program like this, as you know, look to make tweaks, kind of you hit your lowest hanging fruit early, which may be, say, casing strings, when we talk about well design, and then the more difficult tweaks come later. Exact nozzles program, exact fit program, you know, all the other little pieces that will save time off, but maybe not as dramatically as, say, eliminating a casing string. So I'd say we'll never stop trying, but obviously, we. In any design change, you always hit the lowest hanging fruit first, which means you get your biggest impact first. No, so like, that's why I said, I think we're already probably in that 10% savings range and, you know, end of the Q4, beginning Q1, you know, looking to fifth average 15% or better over the year, but as the year goes on, continue to tweak that, and tweak that, tweak that, tweak our science to find a little bit more. But yeah, if you were to draw it out, it looks like an asymptote, but you know, at the same time, if you are open-minded and fit for purpose, you'll always find something. Understood. Thanks for the clarity. Our next question comes from Gabe Daoud with Cowen and Company. Your line is open. Thanks. Hey, morning, everyone. Was hoping, Joe, we 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%-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. Yeah, Gabe, happy to take that. You know what, what I mentioned earlier, going into 2024, priority is really gonna be on, 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'll get us off to a good start getting into 2024. You know, we'll, we'll obviously, provide some, some more formal guidance, as we move forward, but in the near term, you know, we are, prioritizing capital efficiency and cash flow versus, any, you know, meaningful headline production growth. Now, you know, hopefully, we realize all these efficiencies, get going, hoping to do better. I think that's the time when we look at adding some additional activity with reinvesting back in the asset base over time. But, you know, give us some time here to put all these things in motion. Okay. Understood. Thanks, Joe. And then, I guess as a follow-up, you highlighted a lot of the, obviously, cost savings on the, on the capital front, but just curious, you did another good job here on LOE. How does LOE trend into 2024, and do you think there's more you could squeeze out of there? I think our biggest opportunity on LOE long term is fixing our failure rate. Our failure ESPs account for about 5/8 of our artificial lift. That's where our highest failure rate is. And that's probably 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, you know, 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 things. You know, 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, you know, that portion of our spend is neighborhood $50 million a year. It's, and it's all driven by the rate at which wells fail. So it'll be a big focus of ours in 2024 to try to, you know, whittle that down and see if over the, you know, next couple of years, we can't cut that in half or reduce it by 75%, ideally, in time. But that, 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 our, basically improve our chemical spend, with some in, you know, larger infrastructure projects, that's gonna take, you know, some time to implement. 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. I'd say those two, those two areas are gonna be our primary focuses on, on LOE, but they'll take, those will probably take longer to come to fruition. Got it. Thanks, Russell. Thanks, everyone. Thanks, Gabe. There are no further questions at this time. I will now turn the call back to Joe Gatto for any closing remarks. 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. As always, with any questions, please feel free to reach out. Thanks again. This concludes today's conference call. Thank you for joining us. You may now disconnect.