Good afternoon. Welcome to the Earthstone Energy's Conference Call. At this time, all participants are on a listen only mode. A brief question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference call, please press star zero on your telephone keypad. As a reminder, this conference call is being recorded. Joining us today from Earthstone are Robert Anderson, President and Chief Executive Officer, Mark Lumpkin, Executive Vice President and Chief Financial Officer, Steve Collins, Executive Vice President and Chief Operating Officer, and Scott Thelander, Vice President of Finance. I'll turn the call to Clay Jeansonne, Director of Investor Relations. Thank you. You may begin. Thank you, welcome to our 1st quarter 2023 Earnings Conference Call. Before we get started, I'd like to remind you that today's call will contain forward-looking statements within the meaning of federal securities law. Although management believes these statements are based on reasonable expectations, they can give no assurance that they will prove to be correct. These statements are subject to certain risks, uncertainties and assumptions as described in our annual report on Form 10-K for the year ended December 31st, 2022, our quarterly report on Form 10-Q for the quarter ended March 31st, 2023, and the 1st quarter of 2023 earnings announcement. This document can be found in the investor relations sections of our website, www.earthstoneenergy.com. Should one or more of these risks materialize or should underlying assumptions prove incorrect, actual results may vary materially. This conference call also includes references to certain non-GAAP financial measures. Reconciliation of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement issued yesterday. Please note information recorded on this call speaks only as of today, May 4, 2023. Therefore, any time sensitive information may no longer be accurate at the time of any replay listening or transcript reading. Today's call will begin with comments from Robert Anderson, our President and CEO, followed by remarks from Steve Collins, our COO, and Mark Lumpkin, our CFO. We'll have some closing comments from Robert. I'll now turn the call over to Robert. Thanks, Clay, and welcome everyone. Thank you for taking the time to join us today after what I suspect has been a really busy morning for you all. Earthstone entered 2023 strategically advantaged with an enhanced and increased scale in the premier Permian Basin, with a deep and high-quality inventory and a strengthened financial position. This strategically advantaged position is clearly apparent by the solid results we posted once again. I'm pleased to say we are off to a great start this year with these strong results forming a solid foundation to build upon during the remainder of 2023. Slide 5 of our investor presentation that has been posted on our website highlights the significant performance increases we have achieved compared to the first quarter of 2022. Earthstone's operational excellence continued during the first quarter of 2023, with total production surpassing our internal forecast and consensus estimates. Our low decline, stable production base and strong new well results drove our production outperformance for the quarter. We reported first quarter production of 104,450 BOE per day with oil over 46,000 barrels per day. We have now had two quarters in a row with production approaching 105,000 BOE per day and continue to showcase the quality and productivity of our inventory. Steve will highlight several wells that drove our strong quarterly outperformance. The strength of our operational performance was also reflected in our strong financial results. Near record level production, combined with our low cost structure, led to adjusted EBITDAX for the quarter of $267 million. This robust EBITDAX and rigorous capital investment discipline led to the generation of free cash flow of approximately $42 million in the quarter. This free cash flow for the quarter allowed us to continue to execute our plan to reduce debt, lowering our debt to just under $1 billion with a similar amount of liquidity, which Mark will highlight further. The strong overall performance we posted for the first quarter clearly represent the merits of our focused, proven acquisition strategy. At Earthstone, we continuously focus on creating long term value for our shareholders while fostering a culture of doing the right thing. Public confidence and our reputation are valuable assets. As such, we place critical focus on reducing our environmental impact and conducting business and interacting with our employees, contractors, landowners, suppliers, governmental entities, the public and the communities in which we operate responsibly and ethically. We are also committed to providing our employees and contractors with safe working conditions in an environment conducive to creativity, continuous improvement and maximizing job satisfaction. We believe providing ESG related information and metrics to our shareholders and other stakeholders is essential while communicating how we plan to progress over time. Regulators have continued to increase the threshold by which we must operate, we are investing the necessary capital to do so. In order to communicate with our stakeholders in a transparent and open manner, we are working on our inaugural ESG report. We expect to have our report published by sometime next quarter. Now I'd like to turn the call over to Steve Collins to provide an update on operations. Thanks, Robert. Good morning, everyone. First quarter was another outstanding quarter for the operations group. We maintained our rig count at 5 during the quarter, with 3 in the Delaware Basin, 2 in the Midland Basin, drilling a total of 16 gross wells and 12.4 net wells. We put on production a total of 15 gross and 12.8 net operated wells. As Robert mentioned, our operations team brought some great wells online during the quarter. We have shown the areas and results of these wells on page 12 of our updated corporate presentation, which is available on our website. Let me highlight a couple of those pads. We completed the Jade 34-3 Fed pad, where we have approximately 52% interest on acreage acquired from Chisholm in the Northern Delaware Basin, Lea County, New Mexico. The wells targeted the first and second Bone Spring intervals. The four wells had an average IP30 rate of 1,240 BOE per day from laterals averaging 9,900 feet with an average oil percentage of 91%. In Eddy County, New Mexico, also acquired from Chisholm, we completed the Dark Canyon 15-22 State Com two-well pad that delivered an average peak IP30 of 1,422 BOE per day, which is approximately 69% oil. The average lateral length of these two wells is about 7,050 feet, and we hold 100% working interest in these wells. At our El Campeon project on the New Mexico-Texas state line, we recently drilled two of the six wells scheduled for the project and have two additional wells slated to spud early May. The lateral lengths for the 6 wells will range from 9,400-10,000 feet. We have significant ownership interest in these wells and expect the first well to start producing in August. These are the first wells drilled across the New Mexico-Texas state line. In early February in the Midland Basin, the WTG 5-234 two-well pad in Reagan County was put on production. We have 100% working interest in the Wolfcamp Upper and Lower B wells that have an average lateral length of approximately 9,850 feet. The wells had an average peak IP30 rate of 945 BOE per day, and the production stream was around 77% oil. This project continues to highlight the strength of our Reagan County acreage. At Earthstone, given our efficiency mindset, we take pride in increasing value by improving the operations of acquired assets. I wanna highlight a new slide on page 13 of our investor presentation. Since taking over operations of one of our recent acquisitions, we've improved drilling and completion efficiency significantly. Our drilling practices have increased the feet drilled per day by 34% versus the previous operator. We have also provided a case study of 4 actual wells drilled, 2 by the previous operator, the other 2 by Earthstone. The Anaconda 11-14 2-well pad had a total measured depth averaging 21,000 feet. The 2 wells were drilled from spud to TD in about 32 days. Our Paxy South federal 2-well pad had a total measured depth averaging approximately 23,000 feet and was drilled from spud to TD in only 18 days. A decrease of 46% while averaging an extra 2,000 feet in length. A solid improvement from the previous operator's performance. We've also improved efficiency significantly on the completion side. We have increased the frack stages pumped per day to 8.5 in the Delaware, which represents a 16% improvement over previous operator. This has allowed us to get wells on production sooner and lower completion costs. We've also changed the completion design and flow back strategy since acquiring the Northern Delaware assets. The amount of sand pumped has increased while at the same time reducing the amount of water used. We've also modified our flow back strategy. The combined changes have yielded impressive results, increasing cumulative oil production by more than 30% over a 7-month period. These examples highlight our ability to integrate and make improvements to acquired assets which are value drivers for shareholders. As in the past, we will continue to be laser-focused on reducing costs on our recently acquired assets and across our existing asset base. LOE for the quarter was higher than expected. This was due to a number of items, including higher compression costs, increased labor costs, and EHS regulatory and environmental initiatives throughout our operating areas. We are focused on reversing this trend and have our team working through their specific areas of responsibility to achieve this. Turning to service costs, we are starting to see some good news on that front. Rig rates are showing signs of softening, and we are beginning to benefit as our rig contracts come up for renewal. We also see a softening for cementing services and the cost of production casing. In short, we're cautiously optimistic that service costs inflation is starting to abate, which we may see a little bit in the second quarter results, but more likely be realized in the second half of the year. With that, I'll turn it over to Mark. Thank you, Steve. As usual, I will focus my comments today on providing some additional details on meaningful metrics and key highlights and leave the detailed breakdown for you to find in our earnings release in our Form 10-Q, which were both distributed yesterday. Turning to our financial results, adjusted net income for the first quarter was $109.1 million or $0.77 per share, and adjusted EBITDA was $266.9 million. Free cash flow for the first quarter was $41.8 million. On March 31st, we had $452 million outstanding under our credit facility, and total debt was just under $1 billion. Our debt to last 12 months adjusted EBITDA ratio was 0.8 times. In the near term, we plan to continue to use free cash flow to reduce debt. We are thankful for our longstanding banking relationships. We welcome the three new banks that recently joined our bank group. The $200 million increase in our elected commitments, which occurred in March, took our elected commitments from $1.2 billion-$1.4 billion. We really feel like this support underscores our bank group's recognition of the financial strength of Earthstone and the high quality and sizable asset base we have built over the past several years. This increase to our elected commitments provides us with significant financial flexibility and optionality for the future, with close to $1 billion of undrawn revolver capacity. From a production standpoint, we are pleased to significantly exceed our internal forecast and Wall Street consensus estimates, achieving production of 104,450 barrels of oil equivalent per day, which was comprised of 44% oil, 30% natural gas, and 26% natural gas liquids. We have guided toward 2023 production of 96,000 to 140,000 barrels of oil equivalent per day. From a cadence standpoint, notwithstanding what was a really strong first quarter, our year is unfolding as expected, and we do still anticipate a step down in production levels in the second quarter, with the second quarter most likely being our lowest production rate for the full year and also our lowest oil cut for the year. We expect production to pick back up by around mid-year, with the second half of the year likely increasing from the second quarter daily production rate. As Steve mentioned, our lease operating expense was a bit higher than expected, with LOE coming in at $9.36 per BOE for the quarter, which was about $0.74 per BOE above the midpoint of our guidance. Starting out the high, the year high relative to our guidance puts us in a position of working hard to get back within in that range. Our team is working really hard to accomplish that goal. From a cash G&A perspective, our first quarter expenses were just under $13 million, which is right in the range of our full year guidance on an annualized basis and represents a cost on a per BOE average basis of $1.38, which compares very favorable to our peers. Moving on to CapEx, we invested $202 million in the first quarter, which is right in line with our plan and consistent with our expectation that CapEx would be a slightly bit more front half weighted than back half weighted. For 2023, we still expect to invest between $725 million and $775 million of capital, with the second quarter CapEx expected to be somewhat similar to what we saw in the first quarter, with slightly lower CapEx in the second half of the year. Please see yesterday's earnings presentation for more detailed information on our 2020, 2023 guidance, which has not changed. With that, I will turn it back to Robert for closing comments. Thanks, Mark. Looking ahead, we will continue to prioritize debt reduction with our expected substantial free cash flow. Having said that, we continue to believe scale matters in our business, and we will look forward and look for accretive assets that will increase our size while simultaneously creating additional shareholder value. We believe we have built a company that offers an attractive value proposition to investors, including having a solid balance sheet with one of the highest free cash flow yields at one of the lowest enterprise values to EBITDA multiples in the E&P sector. A current valuation that is significantly below our total proved reserves, which stand currently at $4.6 billion and is $1.7 billion higher than our current enterprise value. Our deep inventory, long history of operational excellence and consistent performance position Earthstone to continue outperforming for years. Our team has a long history of creating value for shareholders. We will continue to work diligently to ensure that the long-term value we have created for our shareholders is ultimately recognized. I'd now like to turn the call back over to the operator for the Q&A portion. At this time, we would like to begin the question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment please while we poll for questions. Our first question comes from the line of Scott Hanold with RBC Capital Markets. Please proceed with your question. Thanks, all. You know, you've had some pretty solid performers the last couple of quarters. You know, obviously without, you know, the, I guess, we'll call it the noise of, you know, acquisitions in the numbers. It, you know, looks. It, you know, it's really much more evident. It looks like the well performance you have, you know, really reinforces that. My question is, you know, ultimately, as you take a look out over the next, you know, and I think you said about 10 years of inventory, can you give us the sense of, you know, how you, how confident you feel in the quality and the depth of that relative to what you've drilled here recently? Yeah. Thanks, Scott. It's a great question. Obviously, we have a portfolio of assets, and we are maximizing the value of our co-development or resources in the front part of, you know, a multiyear plan here of 10 years. As we get out to year 7 through 10, it probably looks a little different. Definitely over the first few years of our plan, we expect that what we've been drilling will have similar results for the next several years. Okay. you know, I guess my follow-up is, you know, on M&A, obviously you gave some pretty good color on, you know, how you think about it. But, you know, maybe more specifically, you know, what does the market look like right now? Do you find that, you know, bid-ask spreads are reasonable? And, you know, are there more opportunities in the Delaware versus the Midland at this point? The market will always speak, and deals always seem to get done, so somehow the bid-ask spread gets overcome. We've seen deals here recently where there's, you know, some kind of earn-outs and things like that to help the buyer and seller mutually agree to get something done. It's always a problem that we, as buyers, have to negotiate around, and we'll be creative as anybody to try and get deals done if that's what it takes. There's a good pipeline of opportunities in both the Delaware and the Midland at the moment, and I think that will stay true for the next 12 to 18 months as private equity backed teams as well as non-core assets get, you know, pushed down the food chain, you might say, or people need to monetize for whatever reason. We're pleased with what we're seeing right now and our guys are pretty busy looking at a number of different opportunities. Yeah. I would assume that you all are in pretty much every data room or opportunity. Just kind of curious, there have been, you know, a couple decent sized deals that have happened on both sides of the basin, and I would assume you looked at it. Just at a high level without being too specific, do you find that, you know, your price was sort of the reason that you all didn't come out on top on some of those, or was it something else? you know, price is probably the biggest driver in a lot of transactions. Let's be honest here, we're not looking at deals that are $3 billion, $4 billion, $5 billion, right? I mean, there is a limitation to, even though we like to look at those, how much we could actually go out and do. In the deals that we look at, usually it's price that's driving the answer, and we're focused on adding value, creatively to this whole Earthstone business that we've created over the last two years, and we don't wanna do something that's gonna change our stripes. All right. Thank you. Our next question comes from the line of Neal Dingmann with Truist Securities. Please proceed with your question. Afternoon, Robert, I guess pretty straightforward. Given what you said about having, I believe the nearly or the lowest EBITDA multiple and highest free cash flow of the entire group, which, you know, our estimates would totally support, and having the strongest balance sheet, why not expedite the shareholder return plan versus, you know, kind of late in the year or next year? Yeah. good question, Neal, It's something that we as a board and management team talk a lot about. We just haven't made that direct commitment yet because we're gonna continue paying down debt, even though, you know, the balance sheet is in good shape and, you know, our leverage is under one time. We're continuing to look at all these opportunities. I wanna make sure that the time is right when we do that, 'cause it's a commitment that you make that you probably can't break, and we're pretty good at keeping our word when we're gonna do something. We're just not ready. A little bit of it could be our size, too. You know, at, at $2 billion market cap, is that the right size to initiate or institute something? You know, I'd say keep watching. Sooner or later, that probably is something that we come to, a plan, but we're not ready to do it this quarter for sure. No, that's understood. You guys certainly always do what you're gonna say. I appreciate that. Secondly, just on when you look at, you know, on service costs out there, the way I wanna ask that is, seems like you and others maybe are starting to see a little bit of softness. If you get that and so you get end up, you know, some savings that you and Mark don't have in the plan, would you just, you know, sort of stockpile those savings, put them on the balance sheet, or would you continue to keep the plan as active, which would result in even, you know, higher activity? We're probably not ready to have higher activity yet. You know, New Mexico is a great asset for us. We've got 3 rigs running. Steve might beg to differ some days, but I think it's working pretty efficiently. You know, we always have something going on in the field. We're walking pretty good now, and at some point, we'll get to a position where we can run and maybe we add activity. Again, a lot of permitting timelines that you've got to rely on and, you know, the infrastructure, all those components need to, you know, fit together really nicely. Right now we like the optionality that we have. Running 3 rigs, you go to a higher level of activity and that could, you know, limit your optionality in some cases. Right now we're gonna stick with what we got, deliver the free cash flow, and if we get some extra, we'll pay down some more debt, and hopefully we'll be able to find some transactions we can spend that money on. No, I'm glad to hear it. I appreciate both the financial and operational optionality you have. I think it's a leading characteristic. Thanks, Neal. Our next question comes from the line of Michael Scialla with Stephens Inc. Please proceed with your question. Good morning, everybody. Just wanted to follow up on the last question on your activity, and you mentioned, you know, some of the constraints on the Delaware side. When do you think you could tilt more toward the Delaware? Is 2024 possible to lean more on Delaware versus Midland, or is it further out than that? It's possible, Mike, to do something in 2024. We're, you know, permitting wells for the middle of 2024 already. It has to do with, you know, some capital we're spending this year on the infrastructure side and just making sure that, you know, we've got everything lined up that we need to. Plus, again, it's gonna be a balance between commodity prices and service costs. You know, there's no reason to accelerate into, you know, a high service cost environment if the commodity prices don't, aren't beneficial to us. There's a lot of balls we're juggling right now, and it won't likely happen this year to accelerate activity out there, but it could in 2024. Okay. Just wanted to ask another question on, you know, your acquisition strategy. Sounds like there's a lot of things in the pipeline that you're looking at. If, you know, it looks like you've been able to buy things in the past at kind of PDP value. If you don't get the right price, is there an opportunity now, given you've got a pretty good sized footprint in both the Midland and Delaware, wondering if there's an opportunity to pick up, like, small interests around the area where you're not necessarily buying these larger marketed packages, but smaller pieces where you could replace a lot of the drilling inventory that you're drilling up every year? Yeah, good question. we do focus on that as well as, you know, the larger packages, whether that's trying to do a trade with somebody so we can, you know, bulk up in an area that we're planning to drill a year or two from now, or just flat out buy out, you know, either partners or, you know, smaller operators or what have you. every rock is overturned for us to look at acquiring more assets within our footprint and maybe even expand our footprint a little bit. in both basins, we're looking at all options to increase our inventory. Appreciate the answers. Thanks, Robert. Thanks, Mike. Our next question comes from the line of Subash Chandra with Benchmark. Please proceed with your question. Hi, Robert. Maybe, Mark as well on this question. Can you just review the, you know, the non-recurring CapEx this year? You know, if it, if it's changed at all, I think on the infrastructure side. You know, would you hazard a guess as to what sort of deflation you might see in 2024, keeping the program flat? Sure. I'll try to hit that one, Subash. First, if you look at our guidance, the midpoint of our total CapEx is $750 million, and we sort of lay out what portion of that is D&C in both the Delaware and the Midland, and then what non-D&C is. If you, if you back that out, it's about $92.5 million, that's other stuff. Of that, you know, the infrastructure's a decent chunk of that, and we are, you know, spending that through the course of this year. That is a bit elevated relative to what we would expect in 2024, but I don't think it's gonna, you know, subtract, like, $30 million or $40 million relative to next year. From a, like, deflation standpoint, I'm not sure that I'd exactly think of it as deflation, more so just a little less required activity. I mean, there is stuff that we're doing in Delaware, in particular this year, that is sort of one-time events, and I would say that's probably $20 million of the 92.5. Okay, Mark. if I sort of understood that, what would be the sum total of the two? Also when I think of, you know, do you think of these as sort of truly non-recurring, or is there sort of that non-recurring, you know, the recurring non-occurring, element that we sometimes see? I think of the 92.5 that is not directly Delaware, Midland, D&C, probably $20 million of that is truly non-recurring. If you wanna say next year it's seventy-two and 0.5 versus 92.5 this year, I think that's directionally close. Also there's a piece of non-op drilling in your $92.5, Mark. Yeah. That's right. Right? Take that out because it's a sort of a, I mean, we have some identified and some view of what's happening on our non-op development program, which is truly optional for us. We don't have to spend that capital. We can, you know, go non-consent on AFEs, or we could sell them. Back that out as well and, you know, you're $30 million, $40 million, $50 million of sort of recurring infrastructure or non-D&C. Got it. Okay. You know, I guess to the point on your non-op, and tying that to maybe some of the, you know, service cost, I'm not sure if it's deflation as you, as you said, but the Permian has been in a bubble. Do you think some of this looseness is Permian specific, or do you think it's just some of that, you know, sort of dry gas stuff that's making its way to the Permian? What are you sort of seeing in the non-op activity? I don't know that that has really any bearing on the activity being more or less, if that's kinda where you're going with it or whether it's, deflation or cost coming down or what have you. It's definitely, we're seeing some equipment move around a little bit, and we're seeing, you know, service companies talk about spending more time in oily basins from gassy basins, and they're trying to keep all their people employed and all their equipment working, right? It makes sense that some of that is gonna filter its way to the Permian. Okay. Yeah, Robert, I guess, right. I think, thanks for that. How much do you think it's Permian specific, you know, activity levels dropping? There's some of that. As private guys have sold to public companies, and you've seen this multiple times over the last maybe 12 months, but at least the last 9 months, the privates are running multiple rigs and the public buys it, and he's not gonna run as many rigs on it. There's some of that. My view is if they're high-spec rigs, they're being picked up by somebody, and lower-spec rigs are headed to the yard or laid down. We're definitely seeing some of that. We're seeing some availability of services that probably a year ago, Steve, we weren't able to get on anybody's docket for a frack company even if we wanted to, for a period of time. Now I think there's some alleviation going on in services. We're upgrading in some spots. Yeah, definitely. Yeah. Thanks for the color, Robert. Thanks, Subash. Our next question comes from the line of Charles Meade with Johnson Rice. Please proceed with your question. Good afternoon, Robert, and hello to the whole Earthstone team there. I'd like to ask a question, ask you guys to go into more detail on the El Campeon project. A couple of things I'm curious if you'd share is what zones you're targeting with those six wells. What the spacing is and whether they're designed to test, you know, kinda inter zone, or, you know, intra or inter zone spacing. More generally, my impression is that's one of the most prolific areas of the Delaware Basin. This seems like it'll be a big, an important pad result for you guys. Do you see it the same way? Oh, I absolutely see it the same way. We bought the Titus assets because of... I mean, this was really the key driver to it, is the inventory, and the rock quality there. We're drilling wells in the first, second, third Bone Spring and Wolfcamp, Upper Wolfcamp section. We're drilling all of them. And we've every one of those zones is, has produced either on this acreage or directly offsetting it. It's not like we're testing anything new here. We're typically 4 wells per bench or target zone. Sometimes that can be 1 more or 1 less. It depends on, you know, thickness directly on the location. It could also be whether we got an existing well, and we need to back off spacing a touch. Really, the pads are set up and the acreage is set up to do 4 wells, quite easily. And that's what we're executing on. Thank you, Robert. That's it for me. Thanks, Charles. Our next question comes from the line of Jordan Stuart with GoldenTree. Please proceed with your question. Hey, guys. Thanks for taking the question. I guess first, just looking at the hedge book, it looks like you guys didn't really layer on any incremental hedges. Curious to get your latest thoughts on the strategy. Would have expected potentially layering some in after the OPEC cut, but how should we be thinking about the hedge book going forward, and when do you start layering in hedges in 2024? To the extent you could discuss the structure of those hedges. Sure, Jordan, I'm happy to take that. First, let me just start with sort of where we were at the beginning of this year or around the end of next year. We were about 40% hedged on both oil and gas. I would expect by the time we get into January, we're probably somewhere close on both oil and gas. We did actually layer in some 2024 volumes right after the OPEC announcement. I think that was 3 weeks ago. If you see, there's 2,500 barrels a day of collars that we added actually second half of 2023 through full year 2024. That's our sort of start on the 2024 program. I would expect by the time we talk again in August, we'll have layered some more hedges on. I wanna say last year, August, we were probably 15%-20% hedged for 2023. I'm not committing to being 20% in August, but I do think you'd expect to see us having layered on some more hedges by then. You know, we have employed a variety of structures that give us downside protection but also some upside. You know, we've done some puts. In some cases in the past, we did collars and prices fell, and we converted the collars into puts. In some cases, we've bought puts, so it's probably been close to a year since we did that. Then we've done swaps as well. I think you can expect us to see a series of a mix of that going forward. On the gas side, it's a little bit situational. Last year, you could get such big upside on a collar. We did almost exclusively collars for probably the back, you know, probably the last 12 months from now. That sort of optionality isn't quite the same as it was. I'm not sure that we'll do swaps for collars there. We are cognizant that the year is passing by, and we tend to like to chip away. We do tend to put some volumes on when we see, you know, a jump like we did a few weeks ago. Again, would expect that every quarter we're adding some hedges for next year. I mean, candidly, we hadn't really planned on adding any more 2023 hedges, but when prices jumped like they did, we went ahead and added some oil hedges for the second half of this year as well, which actually helped the price into 2024 as we got the benefit of the higher second half of 2023 applied toward kind of the full year trade, if you will. Great. You mentioned at the top, hey, at the start of the year, you were at 40% hedge. Is the ultimate goal, you know, starting in August, working through the end of the year to get back to that level of hedging, or how do you think about ultimately where you wanna be? Yeah. I mean, I wouldn't say we're rigid on that. Certainly, like, things could evolve, but I think that's a generally fair way to think of kind of our strategy and intentions. I think everyone in this room would be pretty surprised if we were significantly more, significantly less hedged than about 40% by the time we get into next year. Great. That's helpful. One more from me. You know, you made a comment on the Q2 production being the weakest in the year and the oil cut being the lowest. Just high level, is that going to be like a single digit quarter-over-quarter decline? Or just helping us quantify a little bit more that cadence change? Sure. The oil cut change would be really helpful. Yeah, absolutely. First of all, that is largely driven by our activity in the Delaware Basin. And if you look at our daily production, it almost seems like the daily production knew when we went from March 31 to April 1, because right around there, we had a pretty big step change downward in production. And that is more oily. That's all related to our frack schedule and timing of having to shut some wells in, just the timing of turning lines. And that's going really exactly as planned. I mean, I'll tell you, like, right now, I think we're probably 5,000 barrels a day lower oil production in April than we were during the first quarter. That's completely in line with our expectation. April should be the low month. We'll start to see some volumes pick up as some other wells come online and some of the wells that were shut in start to return to production. Like, if you made me guess, you know, our guidance is 100 is the midpoint, ±4,000 a day. We're obviously at the top end of that for the first quarter. I still think that, you know, we've got a good shot of beating the 100 for the day, 100 a day for the year, but I would guess, like, the very best cases were 100 barrels a day and call it, you know, 42% or 43% oil for 2Q. You know, it may be a little bit lower than that or could be a little higher, but there's definitely a significant step down that we're gonna see. I don't know that we're gonna hit the same production levels we hit in the first quarter in 3Q or 4Q. I mean, we've got a chance of that for sure. Directionally, there's a step change down, like, almost April 1st that you'll see in this quarter's results. We do expect that to, you know, from basically now through the end of the quarter, start ticking up and get, you know, somewhere that's probably in, you know, north of 100, but south of 104 for the second half of the year. Cool. That's helpful. Last one for me. I know, you know, LOE definitely is elevated this quarter. You said you're working towards kinda getting back into that guidance range. Should we expect that to kinda manifest throughout the year and really materialize in the back half, and Q2 should be pretty similar to Q1, or maybe any more detail there would be helpful? Sure. Let me maybe try to answer that one too. Like, from a guidance standpoint, obviously we didn't put out a number $825 million-$900 million for the year and think we're gonna be, you know, at $940 million and change the first quarter. Like, that was high, and Steve talked to some of those reasons, and, like, we're seeing things that we can improve. I'm not necessarily expecting a step change in the second quarter. I mean, some of the same underlying challenges are there, and they're not gonna, like, disappear overnight. Like, I think our hope is that we're back to where we're still, you know, within the range for the full year by the end of the year. I, you know, it's not like we're gonna hit $8 a barrel in 2Q, and all of a sudden we're back in the middle of the range. Probably, honestly, a really good goal would be if we were below $9 for the 2Q, and I don't know that that's gonna happen. I think that's, you know, possibly a stretch goal. We also don't feel like there's no chance that we're gonna end up within the range for the full year. Really, like, practically speaking, we're gonna be shooting just to get under $9 for the full year, and that's not gonna happen in 2Q. Great. That's really helpful color. Thanks, guys. As a reminder, if anyone has any questions, you may press star one on your telephone keypad to join the question and answer queue. Our next question comes from the line of Jeff Robertson with Water Tower Research. Please proceed with your question. Thank you. A question, Robert, on equipment. I think you all inherited 3 rigs in the Delaware Basin from the prior operators. Do you have an opportunity or a need to upgrade any of the rigs you have with maybe some of the equipment that's moving into the Permian Basin? Jeff, just let me remind you a little bit. When we took over Chisholm February of 2022, we inherited 2 rigs, and then we took over Titus. They had 3 rigs running in total between Delaware and Texas and New Mexico. We inherited 0 rigs from them 'cause they weren't running any at the time. We picked up a separate rig just so we could have 3 running in New Mexico. They, they scattered out, right? They're not necessarily on all Chisholm at one time or all in the same area at one time or even all in Titus at one time. We did change out one of our rigs last fall and went to a higher spec rig, so we were sort of ahead of the market, just, you know, just making some efficiency moves, last fall. We feel really good with what we've got going right now in terms of our rigs and their quality. Just a question on managing the business, Robert. Maybe this ties in with some of the production cadence that you all will experience in 2023. How does the scale of the company today impact the, maybe the willingness to tie up capital on bigger size pads for a longer period of time, and therefore your production is create some lumpiness from that? Yeah. In every, the life cycle of your business, when we were smaller and we tied up capital for six wells, it made a difference, and it was really lumpy. If you went back and looked at some of our 2019, for instance, quarterly, production numbers and how we were drilling wells and all that. Today, much bigger, much more resilient, lower decline base production sure does help, and allows us to go develop, you know, like we're doing at the state line area of Texas and New Mexico, a much larger capital investment before wells start coming back online. We have that ability now, and if a pad of three or four wells is a week or two late, it probably doesn't have that much impact on our overall production guidance or performance, right? It... Scale does matter in things like that, as well as a whole lot of other things we could talk about all day long, in terms of being a bigger company. Thank you. Thanks a lot. Operator, we appreciate everybody's interest today. We will be looking forward to speaking with you again after the end of the second quarter. Everybody, have a great day. Thanks. This concludes today's conference, and you may disconnect your lines at this time. Thank you for your participation.