Good morning, ladies and gentlemen, and welcome to the Chord Energy 4th quarter 2025 earnings call conference call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call you require immediate assistance, please press star 0 for the operator. This call is being recorded on Thursday, February 26, 2026. I would now like to turn the conference over to Bob Bakanauskas, Vice President of Investor Relations. Please go ahead. Thanks, Josh, good morning, everyone. This is Bob Bakanauskas, and today we're reporting fourth quarter 2025 financial and operational results, and we are delighted to have you on the call. I am joined today by Danny Brown, our CEO, Michael Lou, our Chief Strategy Officer and Chief Commercial Officer, Darrin Henke, our COO, Richard Robuck, our CFO, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls. Those risks include, among others, matters that we have described in our earnings releases, as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During the conference call, we will make reference to non-GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our website. We may also reference our current investor presentation, which you can find on our website. With that, I'll turn the call over to our CEO, Danny Brown. Thanks, Bob. Good morning, everyone. Thanks for joining our call. Last night, we issued our fourth quarter and year-end results and our updated investor presentation. The materials cover key strategic, operational, and financial details along with our 2026 outlook. I plan on highlighting a few key points. Then we'll open it up for Q&A. Looking back at 2025, in summary, it was an exceptional year for Chord. We continued to improve the business, evolving our development program, driving efficiencies, and enhancing free cash flow. Chord consistently delivered results that exceeded expectations while improving the quality and depth of our inventory and enhancing profit margins. My sincere thank you to all of our employees, who, through their commitment and dedication, have positioned us for continued success. Through these efforts, the team was able to deliver significant incremental free cash flow. Looking specifically at volumes and capital, 2025 oil volumes exceeded original guidance by more than 1,000 barrels per day, while capital came in approximately $60 million lower. Since combining with Enerplus in 2024, Chord has lowered its capital spending nearly $100 million while delivering 6,000 barrels per day more oil production in 2026, and our focus on continuing to improve the business has been strong. Slide 8 shows Chord drove $160 million of free cash flow improvement in 2025 from controllable items, including higher production, less capital, lower LOE, lower G&A, lower production taxes, and improved marketing costs. Importantly, the $160 million of run rate improvements represent 23% of our estimated free cash flow in 2026, and we anticipate making meaningful further progress. Since the pandemic, Chord has been laser-focused on disciplined capital allocation and delivering strong return on capital. We believe making good investments, whether in organic well activity, lease acquisition, or large-scale M&A, is foundational to building a strong and resilient organization and in delivering robust return of capital, and this shows in our results. Slide 6 shows that since 2021, Chord has returned $6.7 billion of capital to shareholders, which is particularly impressive given it is higher than our current market cap. Importantly, we accomplished all of this while significantly growing the business on both an absolute and per-share basis, and while keeping our leverage well below that of our peers. Stated differently, Chord has firmly positioned itself as a leader in the Williston Basin, leveraging its scale and operational capability to grow volumes in a capitally efficient way, leading to strong, sustainable free cash flow generation and substantial shareholder returns. Turning to the fourth quarter briefly, Chord delivered another consecutive quarter of solid operating performance. Oil volumes were at the high end of guidance, capital was below the low end of guidance, and both were accomplished with strong cost control. Accordingly, adjusted free cash flow for the fourth quarter was $175 million, substantially exceeding expectations, and we returned approximately 50% of this amount to shareholders. After our base dividend of $1.30 per share, all incremental capital return was utilized for share repurchases. As we look forward to 2026, Chord's plan builds upon last year's success and remains focused on optimizing capital allocation, generating strong returns, and improving continuously. Last year, Chord set a goal of converting 80% of its inventory to long laterals. I'm happy to report that we achieved that goal by year-end 2025, which was earlier than expected and is a testament to the hard work and dedication of our team. Chord's operational improvements and move to longer laterals have significantly lowered our cost of supply. Slide 15 highlights Chord's inventory improvement in 2025. As you can see, we had tremendous success replacing our low break-even inventory, mostly through improvement of the organic portfolio, but also through select M&A. In addition, last year, Chord lowered the weighted average break-even of its inventory by more than 10% through several efforts. including conversion to four-mile laterals, while also driving capital and operating costs lower. Currently, Chord has 10+ years of low breakeven inventory. Diving a bit deeper into longer laterals, I'm happy to report that execution and performance continued to trend at, or favorable to, our expectations, and we've attempted to highlight the benefit of a shift to longer laterals on slide 10 of our investor presentation. Through long laterals and improved execution, Chord has driven per-foot drilling and completion costs to a very attractive level, and this is demonstrated with program-level capital efficiency improving year-over-year. If you look at volumes delivered relative to capital spent, essentially the inverse of an F&D calculation, you can see the 2026 program is more efficient than 2025. Additionally, Chord's future F&D costs on a company level have trended 22% lower over the past few years, clearly demonstrating that things are going in a positive direction. Speaking of 2026, Chord's 2026 plan is in line with the preliminary outlook we issued in November. As a reminder, we intend to run a low to no oil growth program, yielding average volumes of 157,000-161,000 barrels of oil per day, with capital of $1.4 billion. Our estimates are unchanged from our thoughts last fall, despite some severe weather we've seen in North Dakota to begin the year. From an activity standpoint, we are currently running 5 rigs, 1 full-time frack crew, and 1 spot crew, with the spot crew scheduled to drop around the end of the summer. We expect approximately 80% of tills will be longer laterals, split fairly evenly between 3 and 4-mile wells. At benchmark prices of $64 per barrel of oil and $3.75 per MMBtu of natural gas, we expect to generate approximately $700 million of free cash flow in 2026. In closing, Chord remains committed to delivering affordable and reliable energy in a sustainable and responsible manner, and we have a compelling history of disciplined capital allocation, consistent execution, and high shareholder returns. We are proud of what we've built, a scaled and resilient organization with low decline, significant low-cost inventory, and very attractive exposure to the next crude upcycle, while generating strong free cash flow and shareholder returns in the current commodity price environment. With that, I'll hand the call over to the operator for questions. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press the star button followed by the 1 on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star button followed by the 2. If you are using a speakerphone, please lift the handset before pressing any keys. One moment for your first question. First question comes from Neal Dingmann of William Blair. Please go ahead. Danny, thanks for the time. That's another nice quarter. Danny, my question is just on the long-term plan. It's really interesting, you guys were early putting this out, I think, if I recall, back in early 2024, and, you know, look, since then, oil's gone from, you know, diverged between $55 and $87, yet your plan has remained as consistent as ever. I guess my question is there much that would cause that to, you know, change in any, in any direction, you know, whether it's prices or something else, that caused you to diverge from that long-term plan? Hey, Neal, thanks for the question. Yeah, we're really happy with the quarter and the outlook for the organization. I'd say as we think about our activity levels, you know, the great thing is we've built a really resilient company, and because of that, we are, we think we're able to weather through some of these commodity price cycles and still generate really meaningful free cash flow and shareholder returns. I think our, like, the volatility of our activity program it may be a little muted relative to others, because of that resiliency we have in the organization. you know, if we saw really significantly lower oil prices, clearly, we would go back and look at the plan to say, "Does this make the most sense from a capital allocation decision-making standpoint?" You could see a movement in the program, but, you know, with where we're at now and down to levels, you know, far lower than where we're trading currently, we feel really happy with the plan, the free cash flow generation, and the shareholder returns that we've got. It's a great thing about having, you know, strong subsurface and a strong team, and the asset we've built. Great. Great point. Then just my second on fixed costs, specifically, you know, you and I have always talked about, I know Bakken, you know, generally having a bit more fixed cost than, you know, other areas, the Permian. It's definitely notable when you look at your breakeven costs. Those continue to come down. Could you talk about things that you all are doing? Is it to mitigate these costs? Is it things you're doing to lower the fixed cost, or are you just focused on what you can, more the variable? You know, how are you able to continue to decrease breakevens, you know, as the Bakken still has some of the fixed costs it does? Neal, you know, I'd say it's an organization-wide effort to drive our cost structure as low as we can sort of responsibly get to. That includes capital efficiency improvements. That includes operating expense improvements. That includes, you know, what we do from a marketing and midstream, so a GP&T side. It's really everyone is focused on driving improvement through the business. We just think it's absolutely critical. When you produce a commodity, you've got to make sure that you're focused on your margins, and we are very keenly focused as an organization on our margins. You see that roll through clearly from an F&D perspective, as I talked in my prepared comments. You know, the move. wider space development, longer laterals has had just a dramatic improvement in our F&D, which is really covering on the capital side. We highlight in our investor presentation, the $160 million of run rate free cash flow improvement we saw in 2025 through a combination of multiple efforts. Not just the capital side, but also from an OpEx and really all elements of our cost structure improving. The great thing is that we have, I think, built organizationally tremendous momentum around this, and we've seen success, and we're very focused on continuing to, you know, these are run rate type numbers that we'll carry with us into 2026, and we expect to see improvement on this as we move forward. There's a lot of excitement in the organization around it, and I think we've got more than we can deliver as we move forward. Well said. Thank you, well. Thanks, Neal. Next question comes from Oliver Huang out of TPH&Co.. Please go ahead. Good morning, Danny and team, and thanks for taking the time. Hey, Danny. Just wanted to start on organic inventory. As we kind of think about the ads highlighted in the material here last night, any sort of color on which parts of the basin you all are seeing this come from? How much more running room is there beyond what's been highlighted if this year's 4-mile program goes according to plan? Oliver, what I'll say is that, you know, it's really across the basin that we're seeing this improvement, so it's not like it's one specific area. Really, as you think about the, you know, the 1.3 million acre position we've got is really extensive. As we have lowered our cost structure and continued to work, I'd say, through, you know, the geometry of our development program, as well as incorporating some new assets into the development program, we've just really been able to really refine and improve our inventory position, you know, materially improving the break even on our inventory. Some things that we always thought were inventory, it's just now better inventory than we had before. Some things before that wouldn't have made sense for us to drill, now have really compelling returns, as we look at the cost structure, we're able to apply against it. It's across the basin. As we continue to improve the business as we move forward, I have no doubt that we'll continue to see that we'll continue to see more organic inventory flow into the system. We think about this on the, you know, largely on the upfront side, and I think it's common to think about this from your upfront capital costs, which is important, and clearly we've seen a lot of improvement around that, but it's also about how we operate the wells. As we're able to have these wells flow longer, you know, flow longer over time, have higher production delivery over time, and also has a little bit, if you think about our inventory, our overall inventory relative to the amount of production we're making, and the inventory replace production, it also has a benefit to us there because we're seeing more production from the base wells as we move forward, which will, you know, have lower cut off rates as we move forward and just has us rethink the whole inventory position. We're really working all aspects of it, both from a capital and the OpEx and a productivity side, to get more from the wells that we've got, more from future wells, and it just has a really, I think, bright outlook for our overall inventory position. Okay, that makes sense. Thanks for that detail. Maybe for my follow-up question, we noticed in the 2026 outlook that oil cut is showing an improvement from both Q4 and 2025 levels. Just how much of this is driven by leaning more into the western acreage, where wells carry a lower GOR profile? Also any sort of color on how you all are thinking about GOR trends through the 2030 timeframe for your portfolio? Yeah, it's a great observation, Oliver. You're right, we are moving in. Well, I should say we're actually as we think about the 2026 program, you know, broadly, it's got a little bit more of a weighting over to the western side of the portfolio. We do have good activity around the basin, we're not concentrated in a single area. As we move more out of the historic core of the basin, we do see a lowering GOR. That's a little bit reflected in what you saw for us in Q4 this past year and in our expectations through 2026. We, you know, as you'd expect, we're always monitoring the performance of our wells. We're monitoring where our specific development activity is anticipated to be. You know, there's nuances around shrinking yields that we get from various processes, plates we get, and how we account for that in our three-stream production modeling. You know, taking all that into account, we are seeing a little higher cut anticipated in 2026. Broadly speaking, as we, you know, the wells in the core of the basin, we expect their GORs to continue to increase, but they'll be increasing on a declining base. As our new production comes online, that it will come in with a little bit of a lower GOR relative to the historic production. We're trying to balance all that in the projections that we put out there. Okay, perfect. That makes sense. As we're kind of thinking through the next few years, is maybe just very minimal increases to the oil cut is probably a good starting point? Yeah, I'd say that's a great way to frame it. We don't anticipate seeing it, really, an increase in our gas cut, and it may be that our oil weighting increases, but it will be very slight. Perfect. Thanks for the time, Danny. Thank you. Next question comes from Derrick Whitfield of Texas Capital. Please go ahead. Good morning, all, and great update today. Thanks, Derrick. Wanted to lean in on Neal's earlier question, with my first question. You guys have done a remarkable job of lowering your break evens and increasing free cash flow per share over the last several years. Referencing slide 8, where do you see the greatest leverage to further improve the business on the D&C and base production front? Hey, Derek, really appreciate the question. You know, I like, I really like slide 8 of our deck because it just demonstrates the sort of tangible results we've got from a lot of the efforts we've got going on in the organization. To my earlier comments, we think we have more room to go here. You know, I'd say I'm not focused on any one particular area of this. We think we've got opportunity really across every one of these buckets. And we're seeing progress on every one of these buckets, whether it be production operations, opportunities from our base wells, you know, opportunities to lower, not just... I'm gonna say from this, from the base production, but we've got workovers that would be included in this as well, where we see optimization opportunities. Then continued, you know, continued opportunity to see our cost structure fall as longer, as more longer laterals flow into the system and our development plans. One of the things I know about drilling and completions is as we get more of these under our belt, our performance on them will get better. We've just seen that time and time again. I really have a lot of optimism for each one of these buckets and expect us to continue to deliver improvements over what you see on slide 8 in every one of them. That's great, Danny. While acknowledging you're not highlighting surfactants in your prepared remarks today, really one of the larger operators in the basin in Chevron has been piloting surfactants and has had great success with it in the Permian. How are you guys thinking about the use of surfactants in both new well completions and for workover operations? I think that's a great question, Derrick. It's very topical. I'm gonna ask Darrin Henke, our COO, to comment on that. Yeah, great question, Derek. We've pumped 19 chemical and surfactant treatments already. We're evaluating those results, and as we get additional results throughout the year, we'll, of course, report back on those. We're focused heavily on the production side relative to the chemicals and surfactants at this point, we're also looking at adding them on the completions as well, studying that. We're constantly studying our competitors, be it in the Bakken or other basins as well. If we're not the first company to be trialing some of these treatments, we're gonna be early adopters as we see that the results merit additional pumping. In a nutshell, we've pumped a number of jobs already. We're studying the results on those jobs and look forward to success with those. There'll be more of those down the road. We have hundreds of wells, of course, thousands of wells that we could do that on, potentially. Nearly 5,000 wells in our PDP base. Hey, Derrick, I'll just add on to that a little bit, too. You know, we're talking specifically about surfactants here, but, you know, I'd say maybe as a broad comment, if you, if you see or read something that someone else is out there trialing, you know, you should assume that we're doing the same thing, same thing in here. Either we're already doing it, or we're sort of quickly picking up that same information and looking to trial it internally. We're doing that as a matter of course, but we also, you know, we're doing other things as well, we're excited about and thinking can drive potential improvement for us as we move forward. We've generally been an organization that likes to put up some results first, to be able to come out and talk about that specifically. We'll continue to work these things, and as we see results and have news to share, we'll absolutely be doing that. All right. Fair enough. Great update to you guys. Thanks, Derrick. Next question comes from Paul Diamond out of Citi. Please go ahead. Thank you. Good morning, all. I just want to lean in a bit more on slide eight. You guys talk about $30 million-$50 million in annual run rate savings given the negotiations in marketing. I guess, can you talk a bit about the specifics there and I guess the opportunity set you see going forward? Hey, Paul. Thanks for the question. This is Michael. Yeah, the team's doing a great job on the marketing and midstream side. You know, some of the things that we've seen is this basin has a maturity to kind of its midstream infrastructure, kind of throughout the basin. Contracts are have been long-term contracts, the basin's been around for a while, a lot of those contracts are coming up, have come up or are coming up. As those contracts near their term, we're able to get into new contracts that are at lower cost points, which is fantastic. The teams are continuing to look at that, and I think we still have additional opportunity on that side. It really spans across oil, gas, and water, and really kind of throughout the basin, across many contracts. Keep watching. I think there, as Danny kind of mentioned, each of these buckets have room to move, the marketing and midstream side, no different. Just... Like, on this slide, you can hear the excitement, I think, from the team on this. Really, it's corporate-wide, and what I love about it is, it really kind of shows the commerciality that our whole teams are looking at in terms of not only reducing costs, but really just getting better and more efficient, across the organization as a whole. Some of that's coming with production improvements, some of that's coming through cost reductions, but overall, just raising kind of the free cash flow profile of the company, not only on a 1-term basis, but on a long-term basis. Got it. Appreciate the clarity. Just a quick follow-up. Talking on slide 15, in guidance, you guys plan on telling about 150 locations in 2026. guys, how do we think about you? You added 300 odds last year through a combination of organic acquisitions and then the ground game. Should we think about that breakdown being somewhat similar? Is that a reasonable trend, or is that was that an outlier year? This is Danny again, Paul. Clearly, this is something we're gonna be really focused on, and I think, you know, for any 1 year it may look different. You know, M&A, we're gonna be, as you've seen, we've been very disciplined on this over time. We're gonna pick our spots. When we see something that makes sense for us to do from an M&A perspective, when we think we will be a better organization on the back end of it, you may see us do something like that. That would obviously impact this chart. The efforts we've got internally should be continuing to drive sort of organic inventory replacement. I think it may be, you know, the buckets I think, will be the same. The percentage of any buckets may differ a little year-over-year, and it's just gonna depend upon the opportunities we're able to identify as we move forward. Understood. Appreciate the clarity over there. Next question comes from Noah Hungness out of Bank of America. Please go ahead. Morning. I wanted to maybe start off here on the 26 decline rate. You guys have given us a bit of detail on the production shaping, I guess I was curious if you could give any color maybe on what the 26 decline rate looks like versus maybe the 25 decline rate. Yeah, I think the decline rates year-over-year, broadly look similar on an annual, on an annual basis. Really, that's kind of how we think about things. So I don't think there's a whole lot of change as we incorporate. As we've said, you know, we may see a, on a longer term basis, we see maybe a little bit of moderation and decline, you know, assuming we continue to run a sort of, you know, maintenance level program. As longer laterals have a larger and larger portion of our overall production base, we expect to see a modest, shallowing of our corporate decline rate. Again, it'll be small, you know, very small single-digit percentages in that, but helpful, from a reinvestment rate perspective. You know, it's a tailwind that we've got, but not a huge tailwind, at least not right now. For my second question, could you maybe talk about, were any of your capital activities affected by Winter Storm Fern in 1Q? If so, I guess, what does that mean for the timing of capital spend through the year? Great question. I'd say we had a, you know, it's winter in, it's winter in North Dakota, you know, in winter in North Dakota, it, you just have to... the environment that we operate in. It's something that we're very used to and absolutely plan around. It did impact some of our activity in 1Q, it doesn't change what we think would be the overall shape of our capital investment profile. We've always thought that we would see capital activity increase up through the 3rd quarter and then pull back a little bit in the 4th quarter, we still expect to see that exact same shape playing out through the year. A little bit, we had some roads that were difficult to get down, some wind conditions and some cold conditions that came through where we had to suspend some operations. I'd say nothing, you know, significantly unusual for winter in North Dakota. We think through that as we put our plans together, and the overall shape of the program looks pretty similar to what our expectations were last fall. Our teams did a fabulous job getting the production back online, where we did go offline on production and getting activity back out. Definitely one of the best in the basin when it comes to recovering from a winter event. Well said, Darrin. That's helpful. Thank you. Next question comes from Carlos Escalante, from Wolfe Research. Please go ahead. Hey, good morning, team. This is Carlos, on for John. Thank you for having us. First question, I'd like to lean on what you're doing with the longer laterals. It seems to us that as you drill and spud a lot of those, but you don't till the same amount, that there's a carryover effect in your capital efficiency in 2027. Obviously, we're still not there, and it's far for me to ask you to guide to 2027. Can you perhaps give us a sense of on order of magnitude of how would you expect that to unfold in 2027, meaning capital and capital efficiency as a whole? Yeah, broadly speaking, Carlos, I appreciate the question. Again, I'll reiterate your comment that we're not guiding to 2027 at this point. We're just now coming out with 2026. I will say that, you know, what we're seeing with our, with our development program is we've got some nice tailwinds to 2027. From a capital efficiency perspective, the sort of roll-in of the tills from the capital deployed in 2026, all of which we think will be helpful to a 2027 program. We feel good, feel very good about what we accomplished in 2025. We're really pleased with what we're seeing for 2026, and I think that we've got opportunity that will get even better as we move into 2027. Thank you. That's great color, Danny. Thank you. On the second one, and perhaps more of a miscellaneous question, just in light of what a lot of your peers are or have been signaling in the premier basin as a whole, activity-wise, going down the hole. Just wondering if you can remind us the level of opportunities that you guys think you have. There is some historical context on some other formations. up in North Dakota that other operators have tried out for tight oil development. I mean, obviously it's a fundamentally different play than the Permian Basin, with less stack optionality. Just wondering if there's anything that you can highlight to us, remind us what the optionality is, and also acknowledging that you don't need this today 'cause you have a healthy inventory as you do right now. Thanks for the question, Carlos. The great thing about our program is we think we've got a lot of really good inventory in front of us from a very, I'd say, conservatively spaced, very repeatable Middle Bakken program. Our inventory that we look at, it's some of the widest space within the basin, is very repeatable as we, in fact, we've tried to point out a bit Bakken delivery on a, from a well, it's the lowest standard deviation of delivery from any lower 48 basin out there. It's very repeatable development. The very, you know, our spacing is relatively... Well, actually, I'd say it's, it is conservative with no need to put an adjective around that. so it's conservative spaced Middle Bakken program, and we've got a ton of it. We've got a great inventory picture for the organization. obviously, we are aware of the full column, that sits underneath our acreage position there. We're watching what others do. We watch what folks do in and out of basin and see what we can apply, what we've got. We'll monitor it, and we'll respond as would be appropriate. The great thing is we've got a really deep inventory set with what we've got currently and feel great about our plan. Thanks for the time, Danny. Thanks, Carlos. Next question comes from Nicholas Pope of Roth Capital. Please go ahead. Good morning, everyone. Good morning. There's several comments on water kind of disposal optimization in the market opposition line item, then kind of a, an uptick on spend in the midstream in 2026, you know, mostly focused on water disposal. Curious if there's anything that's changed, I guess, with the water production out of the wells, or if this is just kind of the kind of further on what you commented on the late stage, kind of the development of Bakken and some of the contracts that are in place there, or if anything has materially changed with kind of the field level production of water out there? Hey, Nick, good question. This is Michael. Just thinking about the midstream, and I like the way you kind of characterized that. We talked a little earlier that GORs are kind of called flattening in the basin. Part of that is you're moving into areas that have lower gas. Those areas also have slightly higher water. As we talked about midstream deals earlier, we were talking about a lot of kind of more mature systems overall, especially on the oil and the water, oil and gas side. I'd say the water systems overall, it's more mature, but there are not quite as many of those. There are some areas that we're looking at, whether or not it makes sense for us to invest some in the water side, really to kind of juice our E&P returns overall. These are kind of good projects that will boost our E&P productivity and returns. Incrementally, it's not a lot of capital overall, but it is very kind of productive capital for us to spend. Got it. Like, total, I guess, disposal capacity across the basin, you did a nice job of highlighting kind of the movement of oil and kind of where things are across the basin. For capacity for water, I mean, are you all comfortable with the total capacity in kind of the near term of being able to handle all the water that this basin is gonna produce? Yeah, the disposal capacity is totally fine. Just recognize that disposal capacity is also a little bit more localized than maybe oil export or gas export capacities. There is a need to try to get kind of water disposal a bit closer to your wellbores overall. That's why there is some ongoing capital spend on the water side. Overall, that's baked into kind of all of our economics and our thoughts, and so I don't think it really changes things as we move forward, going forward. Got it. That's all very interesting. I appreciate the time. Thank you. Thank you. Next question comes from Noel Parks out of Tuohy Brothers. Please go ahead. Hi, good morning. you know, I was wondering, did the full impact of your lateral length extensions get captured in your 2025 reserves? Yes. We, you know, we have captured the expectations that we have for the, for the, you know, the wells that we've drilled and the results we've seen. As you're probably noting, like on the three-mile wells that we've delivered, we have, you know, captured that in our reserves. As you probably know, we had actually just recently tilled the, you know, the four-mile well. That's probably on the early side. Obviously, you know, there might be, like, one or two wells on that front, but it's not really fully captured when we think about, you know, the full PUD development. It's, yeah, it is pretty straightforward from the standpoint that what we saw in the 3-mile results, you know, resulted in the, you know, the type of uplift that we talked about, you know, in all of our materials. Great. Thanks a lot. I was just curious about how the timing of that worked out. Just a little while ago, you were mentioning that we can consider the inventory to be conservatively spaced. You know, so much of the focus on the longer laterals, I think, at least for me, has been on how they, you know, raise the tier of the maybe outer part of the footprint to make locations viable that wouldn't have been with shorter laterals. I'm just thinking back, are there implications for infill drilling, especially given the cost structure improvement in the more mature parts of the footprint, you know, that 4 milers, you know, can introduce into the mix? No, it's a great question. I think the answer is yes. There probably is beneficial implications as we get better at drilling these longer laterals. I think also, you know, we don't talk about it very much because it's not a meaningful part of our program. It's a more meaningful part of some other operators' programs in these alternative shaped wells. We like it as a tool in the toolkit, but we're fortunate that we've got such a great and extensive acreage position, that we don't need to drill a lot of alternative shaped wells. We can drill long, straight wells, which we like better. The combination of longer wells and alternative shaped wells, I do think has some implication, and as its costs get down, some implications to infill drilling. We. The important thing is, we think we're effective. We're largely effectively draining the reservoir. We've got good reservoir contact areas. We think we're effectively draining the reservoir with what we've got now. Where these longer laterals and maybe more importantly, the alternative shaped wells can come with the infill drilling, is that it may allow us to go back in and capture some reserves that haven't been really effectively drained. If you don't have the ability to drill these alternative shaped wells, you may not be able to access that very well. I, you know, the combination of longer laterals and alternative shapes, I think it's got a beneficial implication to infill development programs. We really haven't quantified that yet, so I'd say that's gonna be, you know, a lot of that would be upside to what we think about now. As our cost structure on these gets lower, as our ability to execute them gets larger, it probably just, you know, gets better from there. You know, quantifying that, it'd be a small piece of our overall inventory as we think about it today, but certainly a nice potential, you know, incremental opportunity for us to evaluate and continue to add in. Great. Thanks a lot. There are no further questions at this time. I'd now like to turn the call back over to CEO, Danny Brown, for final closing comments. Thanks, Josh. To close out, I want to thank all of our employees for their continued hard work and dedication. Our strategic actions and continuous improvement have created what we believe is a valuable and increasingly rare asset. Chord has a substantial, low decline, high oil cut production base, paired with a deep inventory of highly economic, conservatively spaced, oil-weighted locations. We feel great about our competitive position and have a lot of confidence in our ability to deliver going forward. With that, I appreciate everyone's interest, and thanks for joining our call. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your line.