Ladies and gentlemen, welcome to the Callon Petroleum Second Quarter 2023 earnings conference call. Currently, all participants are in a listen-only mode. After the company's prepared remarks, there will be a question-and-answer session. Please note that each caller will be limited to one call, one question, and one follow-up question. Just a reminder, today's conference call is being recorded. If you would like to ask a question during this time, simply press the star and 1 on your telephone keypad. If you would like to withdraw your question, again, press the star and 1. I will now turn the call over to Callon's Head of Investor Relations, Kevin Smith. Thank you, Stephanie. Good morning, everyone, and thanks for dialing in today. I am joined by our CEO, Joe Gatto, our COO, Russell Parker, and our CFO, Kevin Haggard. During our prepared remarks, we will reference our second quarter earnings release and our supplemental slides, both of which are available on our website at www.callon.com. Today's call will 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 in our earnings press release, both of which are available on our website. Following our brief prepared remarks, we will open the call up for Q&A. I will now turn the call over to Joe Gatto. Joe? Thank you, Kevin. Good morning, everyone. Before we get started, I'd like to formally introduce Russell Parker, our new Chief Operating Officer. Russell brings more than 20 years of operations and strategic leadership experience to Callon, and a passion for the oil and gas industry. He most recently served as the President and CEO of EP Energy. We're off to a great start since he joined in June. I know that you'll enjoy working with him. Now turning to the quarter. We posted strong operational results as production came in above the midpoint of our guidance, increasing sequentially by 7%, while capital spending came in at the low end of guidance. We are also progressing initiatives to reduce our cost structure, with LOE and GP&T for BOE both coming in below guidance. Later in our prepared remarks, Russell will discuss some of his key operational priorities, which include steps we plan to take to further reduce costs and increase margins and free cash flow. In July, we closed on a compelling bolt-on acquisition in the Delaware Basin and a simultaneous divestiture of our Eagle Ford asset position. We are now focused solely on our Permian footprint of almost 150,000 net acres, with core areas of established expertise in both the Delaware and Midland Basin. These transactions also enabled us to improve our balance sheet, putting us in the position to launch a shareholder return program. To summarize a few key highlights for this call, we are executing extremely well. Our second quarter financial and operating results were in line or better across all key metrics. We are drilling faster, pumping more completion stages per day, and realizing the benefits of large-scale co-development projects and improved cycle times. We now have a Permian-focused organization and asset base. We've added core long lateral inventory that is contiguous to our operations, which also increased our scale in the Permian Basin. The combination of having the right assets, plus the right operations team and knowledge base, positions us to improve our cost structure and ultimately our conversion of field-level cash flows into free cash flow. Lastly, we have initiated a shareholder return program. I'm proud of delivering on our commitment to shareholders by launching a 2-year, $300 million stock buyback program. Needless to say, we are eager to start this program this quarter. Given our current valuation in the market, buying back our shares is one of the most economically attractive uses of our cash flow. Moving to operating highlights, we placed 32 wells online during the second quarter, including 3 wells in the Eagle Ford. As part of our Delaware program, we had another successful well targeting the Third Bone Spring formation, expanding the aerial extent of our development of this zone, as shown on slide 6. The well is outperforming expectations and is our best Third Bone Spring shale well to date. Our Third Bone Spring wells are delivering similar oil EURs per foot as our Wolfcamp A results. We are not only adding incremental core inventory as we expand the play, but also improving the economics of the inventory that we are currently carrying in the zone. In sum, the Third Bone Spring continues to elevate its contribution to our development plans across an expanding portion of our Delaware footprint. Operationally, we've delivered improvements in both drilling and completions. In the Delaware, we have lowered our time from spud to rig release by 14% due to improved bit design and consistency of operations. On the completion side, we posted substantial gains in stages completed per day across the Permian. One of the drivers of the gains is reduced downtime from optimized scheduling. This will only improve moving forward with a singular focus on Permian operations. These DNC improvements, combined with simultaneous operations on our large projects, are also benefiting cycle times. I will now turn the call over to Russell for some of his early thoughts on opportunities he sees at Callon. Thank you, Joe. I'm very happy to have joined the team at Callon. I have deep Permian Basin roots, and I feel right at home walking around the oil fields of West Texas. For those of you familiar with me, you know that the majority of my career has been with private operators, where optimizing free cash flow per barrel is not only the key to the culture, but necessary for survival. As such, my constant focus is efficiency, lifting and development cost per barrel, free cash flow per barrel, and innovation to increase inventory. This is an exciting time in the company's history. The work that Joe and the rest of the team have done to build this asset base and strong inventory position, while also deleveraging the company, puts us in a unique competitive advantage compared to our peers. I joined Callon to further build on our advantages. My near-term priorities are focused on improving the capital efficiency of the BOEs we produce and increasing our margins through cost reductions and further innovation. In addition, we will leverage previous infrastructure investments and the natural evolution of our life of field co-development model to further improve capital efficiency. We look to minimize well downtime as we continue to optimize artificial lift systems and improve overall well performance, while also reducing all-in cost per barrel. Perhaps what I'm most excited about is our ability to now focus on a singular area, the Permian Basin. Streamlining our operations, unleashing the full potential of our team, combined with an increased adoption of technology, will help provide improved real-time responses and drive increased ownership of results. These steps will provide us the tools needed to drive down costs, increase margins, and ultimately, help deliver increased free cash flow. While I'm not ready to discuss the exact numbers on cost savings at this point, I know it will be meaningful. As Joe mentioned, we are focused on adding to our peer-leading inventory position by innovation through the drill bit. We are blessed in the Permian Basin with many hydrocarbon-bearing formations, and we have a tremendous opportunity to increase our financial performance, well performance, improve our recoveries, and organically increase our inventory position. I'm excited to be here, and I look forward to meeting with you and updating you in the future quarters about the progress I know we will make on these priorities. With that, I'll now turn it back over to Joe. Joe? Thanks, Russell. I'll pick up with a discussion of the second half of the year. Plan to release a rig this month, maintaining a five-rig program for the remainder of the year. In total, we expect to bring approximately 50 wells online in the second half of the year after setting the stage with our first half capital spend. One of our more notable projects is a 15-well project in our Delaware West area that is targeting full development of the Wolfcamp zone and is just coming online as we enter August. Yet another example of the scaled application of our co-development model. In addition, through our Delaware Basin acquisition, we acquired five wells that were drilled by the previous operator and will co-develop three zones, including the Third Bone Spring. I also wanted to bring you up to date on our production cadence into the second half, following the optimization of our DNC program in the Permian with an expanded asset base and singular focus. As a starting point, the Eagle Ford produced just over 3,000 BOE per day, more than the acquired assets in the second quarter, with a similar oil cut of 70%, as 3 new Eagle Ford wells were brought online in April. As shown on slide 8, we are now scheduled to bring the 5 acquired DUCs online in October, which is later than the next round of Eagle Ford wells that were part of the previous 2023 plans. As a result, our new production profile will now be a bit more weighted to the fourth quarter. Given the net lateral length advantage from acquiring long lateral inventory relative to our Eagle Ford wells, we'll be completing a similar amount of net lateral feet in the second half, despite a lower well count. Also, as part of our production guidance for the third quarter, we've included the impact of an extended force majeure event, a large gas processing facility in the Midland Basin that lasted for two weeks, reducing both oil and gas volumes. To a lesser extent, our range incorporates weather-related disruptions related to a third-party power and midstream services that started in June and lingered into July. In total, the impact on third quarter guidance is incremental to our standard downtime assumptions, is approximately 1,500 BOE per day on a quarterly basis. As we look past these transitory issues in the fourth quarter, we see a strong production trajectory with estimates for 104-108 BOE per day and 63-65 BOPD per day. In terms of our capital spending in the oil field service market, we are seeing prices soften on items like sand, steel casing, chemicals, and other service equipment. Specifically, spot market items like steel casing and sand are being priced down between 15% and 20%. We are also starting to realize price relief in items like chemicals. As another data point, we recently recontracted 2 drilling rigs at rates that were below our previous rates. Overall, we expect to realize an incremental $15 million in savings in the second half, both from service costs and the early impacts of structural design modifications. These savings have now been earmarked for the funding of a similar dollar amount of non-operated DNC activity later this year that has recently been accelerated by the operator. This non-operated activity is associated with the newly acquired assets and is anticipated to benefit early 2024 production. While we have not formally reduced our capital expenditures estimate for the year due to this increase in activity relative to our previous plans, we expect additional service savings to be captured in the coming quarters and complement the design-related savings that Russell and the team are working on. In closing, we've made a tremendous amount of progress over the last 6 months, both operationally and financially. Operationally, we are delivering improvements in DNC times, and our life of field co-development model continues to drive production results that are meeting or exceeding expectations. We achieved our initial debt milestone ahead of schedule and are looking forward to starting our share buyback program. I'm excited about unlocking the full potential of our focused Permian Basin asset base and look to forward to further updates regarding the progress we are making on capital efficiency gains and further cost improvements under Russell's leadership. This concludes our prepared remarks, and happy to take questions. Operator, I'll turn it back to you. ... At this time, I would like to remind everyone, in order to ask a question, press star and the 1 on your telephone keypad. We will pause for a moment so I can compile the Q&A roster. Your first question comes from Derrick Whitfield with Stifel. Your line is open. Derrick? He is no longer there. The next question comes from Zach Parham with JPMorgan. Hey, guys. Thanks for taking my question. I guess first, just on cash return, your free cash flow is gonna accelerate in the second half of the year as CapEx moves lower, and you're gonna be starting on your buyback program. I know you've said in the past you wouldn't really be formulaic with that program, but any color on how we should be thinking about the split between buybacks and debt reduction in the second half? Yeah. Zach, this is Kevin. Why don't I take this? I know many of you on the call would like to know the formula here. I might as well get all the additional information into a single answer here. First, a couple of guide rails that we've talked about in other forums, we shares. Second, we're gonna use those repurchase programs to help support the Callon share price and hopefully take some volatility out of the stock. Our guidance regarding your models is we're gonna let you know our targeted repurchase% during the earnings call for the quarter. For instance, this quarter, the 3rd quarter, we intend to use around 50% of our free cash flow to repurchase shares. That, that ultimate percentage will probably flex a little bit, plus or minus a few percentage points, because some items are, are booked after the quarter closes. Regarding a price limit, or target, the share repurchase decision starts with a view of our NAV under planning price assumptions and costs. For Callon, we see a significant disconnect in our current market valuation. To your other point about how we tend to split that between debt and equity, we do wanna remind you that we intend to do the $300 million repurchase program hand in hand with the additional $400 million of debt paydown. We wanna accomplish both of them over that same eighteen-month answer. Thanks, Kevin. Russell, maybe one for you. First off, congrats on the new role. I know you've only been there a little over a month at this point, but can you give us some thoughts on, on what some of the opportunities are you've seen already to reduce costs and kind of how you can accomplish those? Absolutely. Yeah, no specifics yet. I do think the cost reductions will be meaningful over time. The good news is, we've invested a lot over the last several years in infrastructure that we can now start leveraging, which will reduce our total DC and F, especially on the F side. The other opportunities lie around improving the base production, not only the cost of that base production through design changes, but the amount of downtime through design changes. We're gonna be taking a clean or a fresh approach to all things artificial lift, all things field infrastructure, and also just innovation. Where are we landing our wells? How are we completing our wells? How are we spacing our wells? Just a new, fresh approach to that, that'll help... That, that's gonna help improve both our F&D and our lifting costs and our base production over time. Too early to give you exact numbers on all of that, but I'm telling you, I'm very confident in that opportunity set. Thanks. Your next call comes from Eric. Your next call comes from Derrick Whitfield with Stifel. Your line is open. Hey, good morning, all, and sorry about earlier. Good to hear you. Thanks, Derrick. Perhaps high level for the first question. In light of your portfolio transformation and the improving capital efficiency as shown on slide 5, could you speak to a range of maintenance capital cost scenarios for 2024, assuming current cost and perhaps also the benefit of deflation? Yeah. Derrick, this is Joe. I think it's a bit premature. I mean, going back to Russell Parker's last answer, hopefully you were back on the line for that. We got a lot of things moving real time on the cost side of the equation, not just the service cost, but real structural design costs that, as he said, are gonna be impactful. I, I could say that, you know, we expect that capital efficiency will improve, whether it be on a CapEx to BOE basis or free cash flow conversion of EBITDA. Right now, it's a little bit premature on 2024. We'll let Russell Parker get in the seat for another month before we start pinning him down on things like that. All right, Russell, you're up in Q3. No worries. As my follow-up, referencing slide six, could you comment on the change in your completion approach with the Third Bone Spring Shale that's leading to productivity similar to that of the Wolfcamp? We've tried a few different techniques. This one was more intense in terms of both sand loading and fluid loading. We are seeing reduced, or, or, or less drawdowns to produce the same amount of BOEs that you've seen on some of the other wells. I'd say we still have more work to do here, both in just figuring out what the ultimate inventory looks like and what the ultimate economics will be. I'm encouraged to see that improvement already. I would say look for, not only in just this interval, but as the company progresses, you're gonna see more and more tweaks and optimization and design experimentation to help us improve our cash flow per barrel. One clarification, Russell, if I could. So with respect to co-development, do you view the Third Bone Spring Shale as part of the same pressure tank as the Wolfcamp A? ... I don't think you can make that blanket answer across the area. It also depends on whether or not you're talking about the Third Bone Shale or Third Bone Sand, which are both considered Third Bone by certain operators, but different folks pick the tops at different places. There's not one blanket answer to that. We like what we're seeing in the Third Bone Shale well, early time, I'll tell you that. Great update, guys. Thanks for your time. Thanks, sir. Your next question comes from the line of Neal Dingmann with Truist Securities. Your line is open. Morning, guys. Maybe I'll just ask a little bit on that, that Third Bone Spring Shale, a, a different way. I'm just wondering, now, after the success there, just kinda when I look at your maps, how large an area now do you have confidence that, you know, that's going to be prospective in, in, in that area? It seems to be a very nice add. I'm just wondering how large an area can we start to run with on that? Yeah, Neal, this is Joe. As you can see on, on the map here on, on page 6, you know, covers a, a broad swath of, of wells that we have down now or, or in process and feel good about, you know, the, the, the work that's been done there, not only by us and, and by others. I, I think that's where we're focused right now. Not to say that we, we can't expand this down further south, but this is gonna give you a good representation of things that are either in our current inventory or areas where we, we think are near-term adds. We'll, we'll continue to work on not only the, the Third Bone here, but there's other zones we haven't talked about here today that certainly are in process, like the Wolfcamp C, something that we are doing some additional work on and co-development as we speak, and we'll be able to talk about that. Give us a little bit more time to get into year-end and provide some more inventory updates on Third Bone, and can talk a little bit about where we plan to go next. I think to answer your question, we, we think it's a substantial part of this, this Delaware position that we have. Well, that's great to hear. You know, guys, just secondly, on the infrastructure downtime, you know, you talked about the Midland natural gas processing facility and the sort of weather-related midstream disruptions. I'm just wondering, one, it sounds like all of that now has passed. I mean, I believe. Secondly, on a go forward, just, you know, anything else you can do more to mitigate that, or is that just sort of type of bus-- you know, part of the business out there? Yeah. Neal, it's a good question. It is over. The situation has passed. Long term, yes, we're looking at a variety of options, different, one, different off takes, so that we have multiple parties to work with, to take the gas, and also just different utilization of the gas on, on location. Between all of that and, and time, that will just help us have a, a more robust base production and reduce downtime. Awesome. Thanks so much, guys. Thanks, Neal. Again, if you'd like to ask a question, press the star and the number one on your telephone keypad. At this time, there are no more questions. I'll turn the call back over to Joe Gatto. Great. Thank you. Again, thanks to everyone for, for joining us today. A lot of good things to update you on, and obviously some more updates to come on, on our next call. Again, we look forward to talking to you. Any additional questions you have, please feel free to, to give us a call. Thank you. This concludes today's conference call. You can now disconnect.