Chord Energy Aktie

Good morning, ladies and gentlemen, and welcome to the Chord Energy Second Quarter 2026 Earnings Conference Call. [Operator Instructions] This call is being recorded on Thursday, August 6, 2026. I would now like to turn the conference over to Bob Bakanauskas, Vice President of Finance. Please go ahead.

Thanks, Julie, and good morning, everyone. This is Bob Bakanauskas, and today, we are reporting second quarter 2026 financial and operational results. We are delighted to have you on the call. I'm 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 on our 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 this 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.

And with that, I'll turn the call over to our CEO, Danny Brown.

Thanks, Bob. Good morning, everyone, and thanks for joining our call. Last night, we released our second quarter results, along with an updated investor presentation. In those documents, you'll see Chord delivered another quarter of strong operational and financial performance, which resulted in free cash flow above expectations. Execution remains solid across the organization. Oil production came in at the high end of guidance, while adjusted capital spending finished modestly below the midpoint of guidance. Additionally, we continued making progress on a number of strategic initiatives that we believe will further improve the quality of our business and enhance long-term free cash flow generation.

Adjusted free cash flow for the second quarter was $414 million, exceeding expectations, and we returned 54% of this or $220 million to shareholders through a combination of our base dividend and share repurchases. With Chord's balance sheet growing to $612 million and normalized leverage declining below [ 1.5 ] turn at quarter end, targeted return of capital is expected to increase to at least 75% of adjusted free cash flow beginning in the third quarter. Stepping back and looking at the macro for a moment, we've obviously seen unusually high volatility this year and the outlook for commodity prices, particularly oil, remains uncertain.

Against this backdrop, Chord will remain focused on disciplined capital allocation and driving continuous improvement through the business. And while we expect to see further volatility in the macro, we have diligently built a company that can consistently generate attractive returns across a wide range of price environments. Chord has operated a maintenance plus program for over 5 years. This approach has created a large, resilient production base with low declines supported by an efficient drilling and completions program that delivers volumes and an attractive supply cost. This approach has supported sustainable free cash flow generation and robust shareholder returns.

We continue to believe this is the right approach today even as we leaned into the plus last quarter by raising our full year guide by 2,000 barrels of oil per day through our investment in an array of low-cost, short-cycle base production opportunities. Diving deeper into Chord's continuous improvement initiatives, we continue to make progress across a wide variety of areas, including driving longer laterals, improving cycle times, optimizing the production base, implementing AI and optimizing marketing contracts.

As I mentioned in May, Chord is pursuing various projects to optimize its large PDP base. These activities include accelerating workovers, reducing cycle times for down wells, various chemical jobs, debottlenecking surface constraints, optimizing artificial lift through AI and a host of other projects. Success year-to-date has driven Chord's full year volume above original expectations, as I just noted. Since May, the team has broadened the scope of its chemical workover program to test multiple new opportunities. That is we are testing additional chemical treatments over a larger population of wells.

We are currently assuming only limited volume upside from these initiatives as we evaluate their effectiveness, economic returns and implications for the program going forward. While these initiatives have created some near-term upward pressure on LOE, we believe expanding the program is the right step to maximize the long-term potential of the business. On the drilling and completion side, Chord continues to operate well and set new records. Transitioning the portfolio to longer laterals has been highly impactful for Chord, driving a structurally lower cost of supply and higher returns on invested capital.

Since the May update, Chord has turned in line 4 additional 4-mile pads. And as of today, the company has executed 26 4-mile wells in total. Importantly, Chord continues to reach total depth on cleanouts and execution as well as early performance of the 4-mile program is in line with expectations. Chord remains on track to scale its 4-mile program through the second half of 2026 and into 2027. Looking at cycle times, year-to-date, we've seen some acceleration on the frac side, which has essentially derisked the 2026 development program by pushing volumes to the front end of the year.

The team also successfully executed the basin's first trimulfrac, which we believe could further drive efficiencies in select areas by reducing completion costs while maintaining high execution quality. Additionally, Chord is benefiting from reduced facilities-related capital through equipment reuse and scalable facility design. So you can see Chord continues to make progress driving efficiencies across the business. This has resulted in higher levels of sustainable free cash flow, which in combination with our share repurchase program has driven strong growth in free cash flow per share.

Slide 7 in our investor presentation highlights that free cash flow per share has grown about 30% since 2024 on normalized commodity pricing. And when using actual 2026 pricing, the growth is obviously substantially higher. That's impressive performance, but maybe even more impressive when considering we preserve the balance sheet along the way. Turning to updated guidance. We've made a few fairly minor changes. We continue to expect oil volumes to average 161,000 barrels of oil per day over the course of 2026, which is 2,000 barrels of oil per day higher than our initial outlook, largely due to investing in [indiscernible] based production. On the D&C side, due to faster cycle times, we accelerated some activity to earlier in the year, which increased first half volumes and reduced second half relative to our initial outlook.

On the capital side, our outlook is essentially unchanged. Looking at the quarterly cadence, we are expecting a meaningful reduction in spending during the third quarter as we drop our second frac crew, followed by another decline in the fourth quarter. We've also updated our differential and realization outlook to reflect current market conditions. Unique market circumstances drove Bakken crude to trade at premiums to WTI during the second quarter. Currently, we're expecting that premium to fade over the course of the year.

On the natural gas and NGL side, we also updated differential guidance to reflect current market conditions. Full year LOE expense was raised to $10.30 per BOE, reflecting the additional production enhancement initiatives discussed earlier. Additionally, we have also seen some higher workover costs relative to initial expectations as well as a bit higher nonoperated LOE. Expanding on these additional production enhancement opportunities, I'd like to emphasize that Chord is very focused in maximizing economic returns. If investing a small amount of incremental LOE in short-cycle opportunities today has a high probability of generating strong risk-adjusted cash flow in the future, that's exactly the type of investment we want to make.

Finally, turning to our updated hedge position. You can see Chord has added some incremental hedged volumes over the next couple of years. Currently, we have approximately 38% of our second half 2026 oil volumes hedged and about 18% of 2027. So in closing, Chord remains committed to delivering affordable and reliable energy in a sustainable and responsible manner. We remain focused on the factors we can control and driving improvements across the business.

And with that, Julie, we'd be happy to open the line for questions.

[Operator Instructions] Your first question comes from Bert Donnes from William Blair.

First question would just be on capital allocation. I think you pointed out that you're going to step up that free cash flow payout in the remainder of the year. I just want to make sure I understood that wording. It specifically said 3Q. Should we expect that for 3Q and 4Q going forward? Or just what is the strategy going forward on those levels?

Bert, thanks for the question. Yes, I'd say I would expect to see that in 3Q and 4Q as we move forward. As we talk about this, we've always -- we've been pretty transparent about how we think about return of capital to shareholders. And as we drop below this [ 0.5 ] turn levered on our normalized pricing basis, we've committed we'll return at least 75% back to shareholders. And so we've hit that mark. We expect to do that as we move forward. Now of course, if something happened and we saw our leverage go up, I don't anticipate that, but we'll -- we evaluate it then, but I would fully anticipate we'll be above 75% at a floor of 75% for the balance of the year.

That makes sense. So remaining flexible, but expecting over that 75%. And then maybe on the oil differentials that you mentioned in your opening remarks, -- you're starting to guide almost in parity with WTI, that's better than we've seen in prior periods. But oil is a little bit higher than a year ago. So I was just trying to understand, is that where you see it long term? Or is there upside here? And then maybe any thoughts on third-party operator activity or infrastructure capacity? Just where are we in that supply and demand balance?

Yes, Bert, Michael Lou here. Good question. I think the Bakken overall has traded kind of anywhere from a $2 negative to [ TI ] to $2 positive. We certainly saw some significant positives in the second quarter. A lot of that has to do with where we are in the basin, there's a lot of takeaway and production has been generally pretty flat. And so you're in a really good position from broad differentials in the basin. With the huge run-up in oil price in the second quarter because of the war, we saw a huge backwardation in the curve.

So you saw some of that CMA roll kind of roll through to better differentials. To the extent that you see -- you continue to see higher prices in the front and a bit of a backwardated curve, I think you're going to see really tight differentials. We're not thinking that we're going to get that all through the second half. And so what you're seeing us guide to is something just below WTI, still very strong differentials in the basin. But I would say that if you saw periods where you saw the price spike in the front, you should expect differentials to continue to get better for us overall.

Your next question comes from John Abbott from Wolfe Research.

The first question is really on workovers and the chemicals that you're testing. So to start off, could you just sort of describe what your typical workover program sort of looks like? What sort of uplift that you sort of see typically from the pathways you've done your workovers? And then could you talk about the early test that you've seen on the chemicals and your -- that made you sort of expand into these other testing this wider test that you're doing? And when would you have sufficient data to potentially incorporate more of that into your oil outlook?

Great, John, this is Danny. So maybe a few comments here. So I would say from a workover perspective, our workovers really cover a whole wide variety of different activities. This could be things from ESPs going down to holes in tubing to rod repairs that need to be done. And it could also involve these -- some of these chemical treatments that we're looking at doing.

And so I think it really just depends on sort of the opportunity we see on an individual well. Oftentimes, we'll have wells go down for various reasons. And so we have a whole fleet of workover rigs that work to bring those wells back online. And sometimes, we just think the wells may be producing less than optimal, and we have an opportunity maybe to improve their production. It's not that they're offline. We just think maybe they're suboptimized from a production delivery perspective.

And so it really holds a whole different array of opportunities. With respect to the chemical programs, we've tried some chemical programs through the first part of the year. I'd say it's appropriate to say that we've been encouraged with what we've seen, and we're excited about some of the opportunities, and we've got incremental testing we want to do, and we want to expand that testing as we move out and move further. And so early results have been encouraging. We don't know -- ultimately, we need to see the production hang in for a little longer before we can start really hanging sort of full expectations to it and start to include that as our full volume expectations moving forward.

But I'd say early results are encouraging, which is why you're seeing us expand this program -- why you're seeing us expand this program as we move forward. And as we get more information, it's going to be a little -- I think, a little bit opportunity specific -- there may be some jobs that it's quite evident that inconsistent that we see production increases and or failures where it doesn't work, and we'll be able to sort of understand what that looks like pretty quickly.

Others, it may take us a little more time if we see more variability in the results. So we'll pass that along and incorporate it into our guidance as we're able to get that information and have confidence about it and move forward. And so I look a lot. I want Darrin to also have an opportunity to give any color commentary from his perspective.

Yes. Probably the only thing I'd add to what Danny said was some of the jobs we're doing, we're lowering the pumps, and we're seeing increased productivity there. As we've shown on Slide 6, you can see how we've arrested the decline on a pretty good chunk of our wells through these different opportunities. So definitely encouraged with what we've seen and stay tuned.

Appreciate it. And then your commentary about trimul, you did your first trimulfrac up there. You've talked about doing that in select about opportunities in select areas. I guess, areas -- I mean, I guess, how does that sort of relate as you sort of think about overall inventory? And given this sort of -- given this, how do you sort of think of trimulfracs sort of feeding into next year? What is the opportunity for you there in terms of you sort of think about your overall inventory going forward?

Yes, John, this is Darrin again. So we're really starting to investigate optionality around trimulfracs for next year. And it could be 25% to maybe as much as 50% of our program next year, probably 20% to 50%, somewhere in that range. We're -- it takes a lot of things to make all that work out. We're also looking at remote fracking, which would allow us to trimulfracs not only on one pad, but multiple pads perhaps at the same time. So the team was definitely encouraged with what we saw with the first trimulfracs in the basin.

Efficiencies were was amazing, how nice -- how great a job the team did in standing that up and really improving the efficiency of that frac crew. And so we're excited about it. We're going to look for additional opportunities. And -- but I can't really speak to the inventory, how much of our inventory looking out over the next 10 years that we can do with trimulfrac. But next year, it could be, like say, 20% to 50%, perhaps would be the range.

Your next question comes from John Annis from Texas Capital.

For my first one, the economics on Slide 13 assume 80% contribution from the fourth mile. With 26 [ TIL'd ] and over 50 drilled, how many have 6-plus months of production? And is the tow contribution tracking that 80%? And then separately, is the gap between the drilled and [ TIL'd ] a function of more lumpy completions with simul or trimulfrac? Or is that a normalized spread?

So I'd say let's start with maybe the second part first. It's always going to be a little bit of a lag we've got in how we drill these wells and then getting the completion crews in, making sure all the midstream is in place and the facilities are built and then bringing them online. And so you'll see a little bit of lumpiness as we do depending upon the size of the pads and how the overall development works, but always expect to see a little bit of a lag there. With respect to how many have 6 months of production or more, I don't know that number off the top of my head.

Clearly, we're happy about what we've seen so far. With respect to sort of when we really understand what that fourth mile contribution looks like, I think we're still a little early from that. As we model these things out through simulation, the production profiles look reasonably similar during the early period of the well and then they diverge a little bit as you get forward in time. And so we really need to see as they go through this initial flow period and they start to get into more stabilized flow in the future, you can start to tell the difference on -- really see the difference on how that 4th mile is contributing.

So we're still a little too early there to make a call. We like what we're seeing. Everything we're seeing is in line with expectations, and so we're excited about the program. But I think we're still just a little bit too early to call to validate like we did with 3 miles previously that we're getting full contribution from that last mile. So I'm encouraged with what we saw in the 3-mile program. We're actively monitoring these wells as we move forward. And as we have confidence on whether or not we're seeing incremental contribution from that 4th mile, we'll certainly bake it into our plans and pass that along, but I still think it's just a little too early right now.

Thanks I appreciate that.

I think the one thing I'd add to that, Danny, is we pump tracers on all of our 4th mile wells, and we're seeing tracers from those toast stages back at the surface. So we know those stages are contributing. And so all indications are certainly positive at this point.

For my follow-up, as you broaden the chemical program across hundreds of wells, how are you identifying the best candidates? And are you seeing meaningful differences in response by area or well vintage?

I think the -- again, we're early in the testing phases of this chemical program and the team -- and it's very -- it's not only one type of thing that we're trying. We're trying several different things. And so the team has a selection criteria where they look to see what wells they think may be the best candidates for these types of jobs, and that's going to vary a little bit by the specific circumstances of that well. And so yes, there's a whole -- we're trying several different types of chemical treatments. We do have a selection process for trying to determine which wells are the best candidates, and we're marching through those. We'll execute them, monitor performance, learn from it and then move forward.

But we are -- again, we're encouraged with early results, but we need a little more -- enough so that we want to expand this program. And as we have more information and more data, we'll certainly be passing that along and incorporating into our future expectations.

Your next question comes from Paul Diamond from Citi.

I want to talk a bit about Slide 6, you guys list a pretty robust opportunity set with a whole block of initiatives. Can you put some, I guess, clarification around that, like which ones are the kind of low-hanging fruit versus which ones we would expect to see more over time? Is there any that kind of stand out one way or the other?

So I'd say that, again, as we look at these chemical jobs and really more broadly, our overall base production initiatives, there is a whole wide array of opportunities. Certainly, one of the largest costs and impacts to production we see is if we can improve the run time and efficiency of our ESPs. And so we've got a whole team and in fact, we've organized around the entire organization around really making sure we've got a team dedicated to improving our ESP run time and our ESP performance. And I think we're seeing some strong returns on that program. So we haven't highlighted that here, but I just do want to give the team a shout out for their efforts on that.

And that certainly is something that we see a lot of opportunity from a potential cost structure and run time standpoint. From a chemical perspective, I would say it's -- again, we've got some -- we are encouraged with what we're seeing through several of these different types of jobs. We've seen some pretty significant improvement in well productivity on a few of them we've done. We need to make sure that we understand the mechanism of why that worked and to make sure that it's replicable and that we can do good candidate selection here. So again, as we -- we're excited about several of these things. And as we get some more -- again, as we get confidence in the repeatability of the results, and we'll know that as we are able to expand this program and see the production response of then we'll be passing that on. Darrin, anything to add?

Yes. No, I think you covered it well, Dan. I don't have any additional.

Got it. And just for a quick follow-up. I know you guys are dropping the second frac crew on 2H. Do you have any update on the timing of that? Should we expect that like mid-Q3, late Q3? Just how to think about capital timing in 2H?

Yes. So we dropped that in July. And so we've already dropped that frac crew, which is why we're confident about seeing 3Q capital come down.

[Operator Instructions] Your next question comes from Geoff Jay from Daniel Energy Partners.

I just was hoping to get a little more color maybe on some of the production optimization efforts. Is there an element of that, that's more widely deployed that's a bigger contributor than the others? I would assume the chemicals is probably a low contributor, maybe the run time is a bigger one. I guess what I guess I'm getting at is I think a lot about the AI deployment. I mean, how broadly is that deployed? Is there a lot more room there? Or are you doing a lot with the AI optimization of artificial lift?

That's a great question, Geoff. And I'd say that we've really implemented that pretty widely across the field at this point for our wells that are on rod pump. And really, at the end of the day, almost every well that we've got within the field will end up on rod pump. We've got a few that may be on longer-term gas lift. But essentially, we've got nearly every well ends up on rod pump, and we've been able to use the ability of the computer through artificial intelligence to really optimize that entire rod pump program to ensure that not only are we sort of loading that pump properly, but what that results in is to ensure that the wear on the pump is reduced and that the production is improved.

And so we've done that pretty broadly across the field. I suspect that there's room for optimization on that. But with respect to implementation, it's pretty broadly implemented. The nice thing about that is we've seen the success there. And so now I think you may see us looking at what other opportunities do we have to ensure that the computer can optimize aspects of our operation that instead of being optimized on a daily or a weekly or sort of maybe even less infrequent basis where they could be optimized almost instantaneously to make sure that we're maximizing production.

So I think that was a good win for us and is very broadly adopted across the field as you -- sort of as you pointed out. Now from a chemical standpoint, again, it's going to depend on the specific issues we see with that well and the opportunity of the chemical that we're injecting. But -- so those may be a little bit more specific and bespoke depending upon what's going on with the well, but there are some initiatives like this rod pump that we've done across the entire sort of rod pump fleet. Additionally, I mentioned earlier, we've got a lot of -- we've got a whole fleet of workover rigs that help us continue to make sure that our base production is running effectively and efficiently.

And we're now using the computer to help us schedule all of those jobs. And so as you can imagine, in the past, you would have a human look through and determine as a well goes down, and we have wells going down every day, we've got over 5,000 wells in the basin. We would have to optimize where does that workover rig go next. And so you're making all of those judgment calls about proximity to the next well, the amount of production that was off, the cost of the job, the availability of parts to do the job because you never wanted those things to have any idle time. Well, the computer can do all of that scheduling math very, very effectively and very quickly.

And so we're looking for that sort of scheduling optimization as well, which is not something we may classically talk about as part of our base production enhancement initiatives, but it's a big -- it has potentially a big effect to make sure that we're very optimized on scheduling all those workover rigs out within the field. So long story short, we've got -- I think we've got a lot of different initiatives. Some of them will have more broad impact, as you mentioned, some may be a little more focused. but we think all of them have the opportunity to increase value from our base production, and we're excited about all of them.

And there are no further questions at this time. I will turn the call back over to Danny Brown, CEO, for closing remarks.

Thanks, Julie. Well, before we wrap up, I'd like to thank all of our employees for another outstanding quarter. Their commitment to safety, operational excellence and continuous improvement is what allows Chord to consistently deliver strong results while strengthening the business for the long term. As we step back and look at where Chord stands today, I think we're in an excellent position. We have a high-quality oil-weighted asset base with a long runway of attractive inventory, robust, sustainable free cash flow and one of the strongest balance sheets in the sector.

Those advantages give us confidence that we can continue creating value across a wide range of commodity price environments. I'd also be remiss if I didn't take this opportunity to provide a thank you to a member of our team who will be moving on. Shannon Kinney, our General Counsel, will be returning to ConocoPhillips, where she spent many years to fill their open General Counsel position. We're sad to see her go, are thankful for her contributions and wish her all the best. And with that, I'd like to thank everyone for your continued interest in Chord Energy. We appreciate you joining us this morning, and we look forward to speaking with many of you over the coming weeks.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect. Thank you.

Good morning, ladies and gentlemen, and welcome to the Chord Energy First Quarter 2026 Earnings Call.

[Operator Instructions]

This call is being recorded on Wednesday, May 6, 2026. I would now like to turn the conference over to Bob Bakanauskas, Vice President of Finance. Please go ahead.

Thanks, Natasha, and good morning, everyone. This is Bob Bakanauskas, and today, we are reporting our first quarter 2026 financial and operational results. We are delighted to have you on the call. I'm joined today by Danny Brown, our CEO; and 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 on 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 this 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.

And with that, I'll turn the call over to our CEO, Danny Brown.

Thanks, Bob. Good morning, everyone, and thanks for joining our call. Last night, we issued our first quarter results and our updated investor presentation. These materials outline key strategic, operational and financial details, along with our updated 2026 outlook. I plan on highlighting a few key points, and then we'll open it up for Q&A.

To start, looking at the first quarter briefly, Chord delivered another consecutive quarter of solid operating performance. The team did an excellent job executing through adverse weather conditions and some midstream constraints to deliver oil volumes above the high end of guidance. Additionally, we maintained solid cost control. Adjusted free cash flow for the first quarter was $324 million, substantially exceeding expectations, and we returned $145 million of this amount to shareholders through a combination of our base dividend and share repurchases.

After accounting for lease acquisitions occurring in the quarter, we were also able to send $175 million to the balance sheet. Second, as we assess the macro environment, there is clearly an unprecedented amount of volatility and uncertainty in commodity markets. Chord has been running a maintenance plus program for more than 5 years with the goal of maximizing free cash generation for our stakeholders. One of the key factors influencing this strategy has been the high levels of excess low-cost oil capacity which has weighed on global oil markets and contributed to persistent backwardation.

We will continue to monitor global supply-demand balances and for now, given the uncertainty of how much and how quickly oil volumes will find their way into the market, we are comfortable staying the course with a flat to slight growth volume outlook. Given this, drilling and completions capital is expected to stay consistent with our February outlook. However, we are seeing improvements in cycle times, which accelerates some activity into the second quarter.

Although 2026 capital spending expectations remain unchanged, we do have some flexibility within our program. Over the past 2 years, we have consistently outperformed initial expectations and have generally prioritized capital reduction over incremental volume growth. In the current environment, if efficiencies continue to improve and oil prices remain high, we are inclined to allow modest volume upside rather than focusing solely on reducing capital. For clarity, this does not bias our CapEx higher, but simply means we are not focused on reducing CapEx in this environment and will let incremental volumes roll through should we continue to outperform.

Additionally, Chord is pursuing various initiatives to optimize our production base with efforts centered around maximizing very short-cycle volumes through high-return projects across our roughly 5,000 operated wells. These activities include accelerating workovers, reducing cycle times for down wells, various chemical jobs, de-bottlenecking surface constraints, optimizing artificial lift through the utilization of artificial intelligence and a host of other projects.

Accordingly, last night, we updated our 2026 outlook to reflect a 2,000 barrel per day increase in oil volumes with a slight increase in LOE and capital remaining unchanged. Assuming $80 oil, the net impact is over $40 million in incremental free cash flow versus our February expectations. From an activity standpoint, we are currently running 5 rigs, 1 full-time frac crew and 1 spot crew with the spot crew scheduled to drop around midyear, which because of faster cycle times, is a little earlier than our February expectations.

We continue to expect approximately 80% of TILs will be longer laterals, split fairly evenly between 3- and 4-milers. We've also updated our 2026 guidance to reflect improving oil realizations. Currently, Chord is realizing modest premiums to WTI, and we expect that to persist through most of 2026, given the structure of the futures curve and linkage to waterborne crudes.

Assuming benchmark prices of $80 per barrel of oil and $3.25 per MMBtu of natural gas for the balance of 2026, we expect to generate approximately $1.4 billion of free cash flow this year. With high levels of free cash flow anticipated, we expect shareholder distributions to remain robust in 2026 with a continued focus on a healthy and sustainable base dividend supplemented by share repurchases.

In the current environment, share repurchases continue to look attractive. However, in the interest of avoiding pro-cyclical buybacks, Chord may choose to taper repurchases if and when we see higher oil prices more fully reflected in our share price. In addition, we currently don't envision resuming variable dividends and plan to let excess free cash flow go to the balance sheet. This will reduce net debt and allow us to create per share value opportunistically in the future.

Turning to our updated hedge position. You can see Chord added significant hedged volumes in 2026 and moderate amount in outer years as well. As a reminder, our hedge program is designed to systematically hedge more when prices are above historical levels and conversely hedge less when the strip is below historical pricing. In any prompt quarter, we have the ability to lock in up to 55% of our volumes if pricing surpasses certain thresholds, and the program deliberately moves at a slower pace further out on the curve. Currently, we have approximately 1/3 of our 2026 oil volumes hedged and less than 15% of 2027.

Turning to the long lateral front. I am happy to report Chord successfully executed and turned in line its first full 4-mile DSU development, the Toonie pad. The pad consisted of 5 wells, including 1 alternate shape and Chord was able to clean out to total depth on all wells. Both execution and early performance are in line with expectations.

Slide 11 and our investor presentation highlights the Toonie success as well as Chord's progress on 4-mile laterals in development across the perimeter of the basin. A significant reduction in drilling and completion cost per foot underpins the strong economics of these wells.

Slide 10 on the upper right illustrates a 37% reduction in Chord's D&C cost per foot over the past 4 years. These benefits can be seen in Chord's improving program level capital efficiency year-over-year. If you look at volumes delivered relative to capital spend, 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 cost on a company level have trended 25% -- or 22% lower over the past few years, clearly demonstrating sustained efficiency gains. Overall, we are very pleased with execution and early results from the 4-mile program. As a reminder, Chord is scaling its 4-mile program in 2026 with approximately 40% of TILs and 60% of spuds expected to be 4-mile laterals.

So in closing, Chord remains committed to delivering affordable and reliable energy in a sustainable and responsible manner. We continue to improve the business, growing production while simultaneously improving the depth and quality of our inventory, driving operational efficiencies and enhancing free cash flow.

With that, I'll hand the call over to Natasha for questions.

[Operator Instructions]

Your first question comes from John Abbott with Wolfe Research.

Danny, I mean, I appreciate the opening comments on the macro front. There's a lot of uncertainty there. My two questions are really on growth and on inventory. My understanding from our previous virtual events is that you do have the ability to grow at some point when you -- when there's fundamentals that's more to support the long-term commodity price being higher? How do you think about that appropriate long-term price?

And then the other -- second part of -- the second question is really on inventory. If you do grow, commodity price is higher, how does that change the depth of your inventory as commodity prices, sort of, go higher. So those are our two questions.

Thanks, John. So I think they're both great questions. And from an oil price perspective, I think you're exactly right in our philosophy and that it's not really -- it's not necessarily a specific price, but also what is the durability in the macro setup that supports that price over a long term. And so that's really been fundamentally why we have been focused on, I call it, more of a maintenance program as opposed to a growth program because we have seen just significant behind-choke volumes out in the global market that really could come to market at any time that could undermine our price expectations, and we would invest a lot of capital and not get the returns off of that investment that we may have expected in the -- when we undertook the capital investment in the first place.

And so we don't want to be exposed to that. And as I look at the amount of volume not flowing currently within the global market, I think it's analogous to that. When we just don't know how much and how quickly this volume will return to the market, which means -- so the durability of any price signal is just somewhat -- we're somewhat circumspect on it.

And so -- but if we did see that more constructive macro setup from a supply-demand balance, where we thought the durability of, sort of, let's say, above mid-cycle pricing would be durable for some period of time.

I think we're -- we are in a great position in that we do have a deep bench of low-cost inventory that we could accelerate into and we could deliver some modest growth into the system and think of it sort of mid -- probably mid-single digits. It's something that we would be comfortable with if the structural setup was conducive to that.

From an inventory standpoint, I think if we saw that set up and we're at, let's say, call it, above mid-cycle pricing, and we thought that would stay for some period of time, clearly that's a tailwind for our inventory because we would look at new development opportunities, probably some incremental evaluation on our spacing would be appropriate at that point.

We would -- certainly some areas on the periphery of the basin would come into the fold. And so I think it would be a tailwind to inventory. And so we've been able to maintain 10 years of inventory for the last 5 years. I would expect in a higher commodity price environment if we did push some growth in the system that would also mean our inventory was marching up as well.

Your next question comes from Oliver Huang with TPH.

I wanted to start on the base production enhancement program. There were a number of callouts in the release, AI optimized artificial workover enhanced programs, less downtime among some other stuff. But just wanted to dive in a bit deeper. Are you all viewing this as something that's more structural driving lower base declines for the portfolio across multiple years? Or is this more of a one-time addition on the set of wells the program is targeting. Just trying to understand the sustainability of that uplift better? And just what sort of upside running room there might be beyond what's baked into this year's guide?

I think it's a great question, Oliver. And I think maybe the answer is it's a bit of both. And the reality is we've had efforts underway as an organization to optimize the production base -- from our base wells, we've seen some early success there. And in pricing, in a world where the market has been telling us it needs oil, very short-cycle oil, we've had opportunities to do that. So we've leaned in. And so -- but I'm going to ask Darrin maybe to talk us through a little bit more some of the specifics going on there and some of the early results we're seeing.

Yes. Oliver, we've seen dramatic increase in our productivity on our older wells by -- we've lowered some pumps, some rod pumps lower into the wells. We've adjusted our artificial intelligence to focus on maximizing productivity out of our older rod pump wells and really seeing -- as you see on Slide 12, on the lower right-hand side, you can really see a dramatic impact -- positive impact to base production and really a resting decline on this group of wells.

And we have the teams consistently generating new ideas and as Danny said, it's going to take time to figure out how sustainable these changes are to the wells that are already improved on production, and we'll see how it goes over time. But the team is doing a great job there. And where -- we picked up a couple of additional workover rigs, we're focusing on some longer-term shut-in wells that have some challenging downhole problems and we're finding that we're able to get those wells back online and get those producing as well. And there's a number of wells in that category that we're working on. So while we see these higher prices where we are definitely trying to take advantage of maximizing our base production.

Awesome. And maybe just for my second question, just on the 4-mile laterals, you all talked about verifying the total contribution with tracers on these 4-mile laterals, but just as you all get more data and a greater sample set, is there a point in time or some sort of quantitative benchmark that we should be aware of where you all would, kind of, revisit and start to assume maybe greater than the 80% contribution on the last mile to wells lateral if the data were to be supportive of it?

I think the answer to that, Oliver, is yes, just like with the 3-mile laterals, after we got enough production history, we came out and said we were no longer underwriting that last mile at 80%. We were moving that up to 100% because we were seeing that through the production data. I think it would be sort of a similar case from a 4-mile lateral standpoint. And so it's a little too early for us to say that right now, but we're continuing to monitor our production. And given if we're -- if we continue to see things look positively, hopefully, we'll come out with an update at some point in the future, indicating that we're getting more from that last mile than we're currently underwriting.

Your next question comes from Phillip Jungwirth with BMO Capital Markets.

This is Jack Kindregan on for Phil. Just hoping you could touch on crude differentials a little bit. I think I have a decent understanding of the near-term premium to WTI, but can you help us understand what the second half might look like and why you could still price barrels above WTI at that point?

Jack, good question. Obviously, over the first -- the end of the first quarter and into the second quarter, you're seeing stronger differentials in the basin. Some of that is, as you think about Brent-TI differentials, they've widened, a lot of our barrels get to the coastal markets. And so you're seeing very strong differentials in basin. A lot of that's going to depend on kind of how the broader global markets act, but we think that it certainly will last through the second quarter and maybe beyond into the second half of it.

And you touched on your capital plans for the balance of the year a little bit. But just seeing the oil uplift in 1Q and the better 2Q and 3Q guide is trying to get into the sense of the 4Q dip and just understanding if there's a case for running higher activity there, filling in completion white space just to maintain operational momentum even if it leads to some CapEx creep.

Yes. Phillip (sic) [ Jack ], I think at this point, we're pretty happy with our activity levels. We've got the spot crew, we'll release later this year. And so that we run that crew continuously until we drop it. So it's not really like we're trying -- we need to manage white space on a -- sort of in between an existing program, it's just we'll drop that. And so I don't think there's a lot of efficiency improvement we pick up by pushing incremental activity through the system.

So we're -- I think we're happy with our activity levels where they are right now. We'll continue to monitor the macro situation, but too early for us to pivot off that. We're very comfortable with where we're at now.

Your next question comes from Scott Hanold with RBC Capital Markets.

I was wondering if you could pivot to shareholder returns. You all have had a pretty good appetite to be pretty aggressive with buybacks getting close to 100% in past quarters. It sounds like you want to be a little bit reserved just not to be pro-cyclical, but like when you look at your stock price today, in -- with oil kind of still near $100 a barrel, is this an opportunity for you to continue to be pretty assertive with buybacks and push it a little bit harder? Or would you rather just wait for a much more countercyclical time to get that robust with buybacks?

Scott, I'd kind of frame it this way. Clearly, the -- if you look at the prompt -- if you look at the headline oil price, our stock is not underwriting anywhere near that level in our opinion. And so we really like where our stock's at right now, and I think their buybacks will command. They are very attractive at the current levels. At some point, it may be that we see our stock price underwriting at significantly higher oil price. We're not seeing that today, but we may see that at some point. And at that point, we would consider tapering back on those buybacks to avoid being procyclical. But I like where our shares are right now.

Okay. Understood. And I guess, looking at the Toonie pad, could you just talk about like the learnings from that? Have you seen cost reductions with that pad consistent or better than what you expected? And what does that mean for like 4-mile pad development moving forward?

I'll let Darrin address this. I'd say, generally speaking, Scott, we're really happy with what we saw at the Toonie and any time you get the pad level development, you're just going to pick up efficiencies as opposed to doing one-offs. And so getting to pad is a pretty big cost improvement for us organizationally, but I'll let Darrin expand.

Yes. So we have 12 4-mile laterals now producing and so 5 of them were on the Toonie pad. And we have drilled 33 4-mile laterals. And so there's tons of learnings not only on the Toonie pad, but where we've drilled the wells on other pads, 4-mile wells, and we're consistently getting those wells drilled with 1 BHA. We recently just drilled our first hairpin with 1 BHA. So pretty neat accomplishment there. So the Toonie was just able to put it all together on 1 pad. And so definitely saw efficiencies across the entire pad that we'll take into the future for future pads, but learnings come in on all those wells that we've done.

As far as you asked about the cost and performance, the costs were in line with what we thought we would do on that pad, well productivity is in line with what we thought. So we're very pleased with what we're seeing with our 4-mile program at this time.

We now have a question from Neal Dingmann with William Blair.

My first question, Dan, a little bit maybe more on capital allocation then what you mentioned in the prepared remarks. Specifically, I know you've had -- I've seen a couple of guys now talk about dialing down buybacks perhaps in the current upcycle. I'm just wondering what's your thoughts on incremental buybacks versus debt repayment for the remainder of this year if prices stay here?

Yes. I think, Neal, in the current environment, we think our return on capital framework provides a great framework for us to think about capital allocation. We have -- based on -- we listen to investors and based on a lot of investor feedback, we're not really focused on variable dividends at this point. So I think our return of capital program is really going to be made up of our -- what we think is a pretty strong base dividend plus share repurchases.

We really like the shares with where we're at right now. We do recognize that if we see elevated oil prices, some of that elevated oil price may cause us to think a little bit about is it the right time for us to be buying back aggressively shares. We've said for a long time, we're not fans of pro-cyclical buybacks. That's not something we've been focused on historically, but I don't think with where we're at currently, that's what we're doing. We think the shares are very attractive and they're going to -- they're currently commanding a significant focus of our -- from a capital allocation perspective.

Makes sense. And then second question, maybe around Slide 15, a little bit more than what you said on inventory. Specifically, you all suggest, and I agree, 10-plus years of low breakeven inventory. Can you speak to maybe have the assumptions changed at all when you include maybe what level of kind of your price deck you're assuming here, maybe cost around that, then maybe other things that dictate how you view the breakevens and the corresponding inventory.

Yes. So the inventory that we put out there is really low sub-60 WTI inventory. And so that's really what's determining that count. And so if that -- if our pricing assumptions from a commodity perspective were higher than that, you'd see more inventory on that from an account perspective. So that's what we're assuming on that, Neal. I think if structurally, again, we get to a situation where structurally, we see a longer term, higher oil price than perhaps we would think a little differently about what our inventory position is, and you'd see more inventory flow in. But we're looking at it from a sub-60 standpoint.

Your next question comes from Michael Furrow with Pickering Energy Partners.

Daniel, I want to follow up on that last statement. You mentioned that higher oil prices would unlock some inventory that might not have been economical a few months prior. So would that change your capital allocation priorities? Or would you still plan on targeting your highest return wells first?

I think we would continue to focus on our highest return wells.

Got it. That makes sense. Okay. As a follow-up, clearly, some volatility this morning. It sounds like the message is clear that activity levels are unlikely to change given the current market dynamics. But what are the levers can the company pull to capitalize on higher prices?

Yes. I think we say activity -- our drilling and completion activity, we don't anticipate changing. But we have flexed up on some of the very, very near-term, more OpEx-related opportunities. So the workovers and some of the chemical jobs and these things that really are opportunities across our 5,000 existing wells, we are looking at that because that can deliver very, very short-cycle volumes at incredibly high IRRs and profitability. And so we're looking at those types of opportunities. And then -- and you've seen us deliver some incremental volumes in the first quarter as a result of that. So we're looking at that.

And then the other thing I'd say, Michael, is we continue to focus on improvement across all aspects of our business. And so that's a lever that we continue to pull and have the entire organization focused on is how do we do better -- how do we do better tomorrow. And we've got around 800 people who wake up every morning and come into the office trying to make tomorrow better than today, from a cost structure perspective, from a productivity perspective.

And so that focus -- we focused on that for a long time, and that focus continues because we can't control what oil price is, but we can control what our cost structure looks like, we can control how we develop the field, and so we're focused on that quite intensely. So we'll flex into those opportunities that deliver very robust and attractive short cycle. And by that, I mean sort of more OpEx, things that can deliver some oil next week or next month, you've seen us do that, and then we'll focus on just improving the business across the board.

You have a question from John Annis with Texas Capital.

For my first one in building off of what you just mentioned, I wanted to ask if you could provide some color on the organizational changes you've made, whether it be standing up new teams or shifting allocation of resources that have been driving the improvement in base production optimization initiatives.

It's a great question, John. And we -- I think one of the -- maybe one of the most significant organizational changes we've made recently is we've -- in our production engineering team, we've actually sort of bifurcated that team into those that are looking at our wells that are on ESPs, and I'd call it, our high-rate wells and having a separate team looking at the balance of our wells, which is measured in the thousands that aren't on ESPs and delivering high rate.

As would be natural, you can imagine a team that's responsible for looking after all of that. The natural focus and the appropriate focus is going to be to focus on those high-rate wells, those ESP wells because they're -- they have the biggest impact on your organization. And unfortunately, the reality is that sometimes you don't focus as much on the other wells, which still could provide meaningful value.

But on a relative basis, they just don't come in -- they don't command as much of your attention. And so we sort of recognize that dynamic going on in the organization, and we've now bifurcated that team. And so we have a group that's dedicated just to looking at these lower-producing wells, but there's a lot of them. And then in aggregate, they can have a big impact into what we deliver and what our overall cost structure looks like. So we've seen success with that. I'm really pleased with the results and the focus of that team -- of both of those teams because they're delivering great work.

Terrific. For my follow-up, you're guiding around 40% of 2026 TILs and 60% of spuds being 4-mile laterals, could you provide some color on how the 4 miles spud-to-TIL this year potentially impacts the 2027 production profile and then is there a ceiling on the 4-mile development mix given 50% of your inventory are 4-mile locations and DSU geometry constraints?

Yes. Well, to your point about -- we think about 50% of our inventory is 4 miles. And so I think in a year, you'll see us sort of, I'll call it, an error bar around that 50%, maybe some years will be slightly ahead and some years will be slightly underneath. But generally speaking, I think our development programs will probably largely mirror our inventory makeup. And so -- and so that's kind of how I would characterize it. Now because we're spudding 60% 4 miles this year. Obviously, that's going to roll into '27 from a production perspective. So we've started that ramp this year, and we'll just sort of continue that into 2027.

Your next question comes from Phillips Johnston with Capital One.

I wanted to ask you about the XTO assets. I recall you guys are in the process of re-permitting, I think, most of those wells for longer laterals. So I just wanted to see where we are in that process. And when we might see some of those wells coming into the fray?

Yes. I think as we've worked through -- clearly, as we moved into 4-mile laterals and looking at our spacing opportunities in the lateral lengths that was -- we wanted to make sure we maximize the contribution from that asset. And so we've taken our time in doing that. And so as we look toward developing in that area, I think that's probably more of a late '27 type phenomenon. And so we might get some contribution from it in '27 but more likely going into 2028.

Okay. Sounds good. And then I'm sure you can't comment too much on this one, but what's the latest messaging regarding long-term plans for the Marcellus acreage?

So I think the messaging around Marcellus really kind of remains consistent. We continue to see that as a non-core asset and have been very front-footed and consistent in saying that we're looking to maximize value for our shareholders. And that would include divesting that asset. But I'd say we're not in a rush, but certainly, it's non-core, and we just want to maximize value from it. In the meantime, I'd say it's got very low friction cost to us holding. And you can see from our first quarter results, the significant value that asset contributed. So non-core -- we want to maximize value from it. We are absolutely open to divesting it, but we want to make sure we do that in a fashion that maximizes value for shareholders.

[Operator Instructions]

Your next question comes from John Edelman with Jefferies.

Dan and team, I appreciate getting me on. Just a quick one for me. I heard from NOG earlier this week -- last week, I guess, about a large Bakken package that was coming for sale. Just wanted to get your thoughts on M&A in the current elevated price environment and sort of what type of leverage are you guys, kind of, on an upside scenario, able to kind of stretch to for the right type of inventory mix?

So I'll make some opening comments, and then I'll pass it over to Michael. I think from a positioning perspective, we clearly -- our footprint in the Bakken really stretching across the entirety of the basin means that any package that comes to market there, we think we can be quite competitive on. We can bring synergies to bear, I think, really like no one else can. We've got great supply chains in place. We know the subsurface quite well. And so from -- we're believers in consolidation. And so I think we'll -- we can compete well in any process. but we will also be very disciplined in what we do, and you'll see us -- you haven't seen us win every deal in the Bakken and oftentimes that's been because the market clearing price wasn't something that we think made us a better company at the end of the day. So with those maybe opening comments, I'll ask Michael to fill in with some more color.

Yes, John, there -- I would say that the -- usually when prices are moving very rapidly, there's a bit of a lull in terms of M&A opportunities that are out there. As you've seen elevated pricing for, call it, 2 months now, I think that because of that, you're going to see some assets come to market.

The big question is whether or not you're going to be able to close the gap between buyers and sellers in terms of valuations and see how that goes. As Danny mentioned, we think we're in great shape to be consolidated in the Bakken, but we're going to be disciplined in the way we look at that marketplace.

This looks like all the questions for now. So I will turn the call over to Danny Brown, CEO, for closing remarks. Please continue.

Okay. Thanks, Natasha. Well, to close out, I just want to extend my sincere thank you to all of our employees, who through their hard work, have positioned us for continued success. Chord has consistently delivered results that have exceeded expectations while improving the quality and depth of our inventory and enhancing profit margins. Chord has 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. And with that, I appreciate everyone's interest, and thank you for joining our call.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.

Good morning, ladies and gentlemen, and welcome to the Chord Energy Fourth Quarter 2025 Earnings Call Conference Call. [Operator Instructions] 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, and 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'm 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.

And with that, I'll turn the call over to our CEO, Danny Brown.

Thanks, Bob. Good morning, everyone, and 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, and then we'll open it up for Q&A.

So looking back at 2025, in summary, it was an exceptional year for Chord. We continue 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 capital 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 breakeven inventory, mostly through improvement of the organic portfolio, but also through select M&A. In addition, last year, Chord lowered the weighted average breakeven of its inventory by more than 10% through several efforts, including conversion to 4-mile laterals while also driving capital and operating costs lower

[Audio Gap]

10-plus 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 cost 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 spend, 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 cost on a company level have trended 22% lower over the past few years, clearly demonstrating that things are going in a positive direction.

And 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 to 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 frac crew and 1 spot crew, with the spot crew scheduled to drop around the end of the summer. We expect approximately 80% of TILs 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.

So 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 up cycle while generating strong free cash flow and shareholder returns in the current commodity price environment.

And with that, I'll hand the call over to the operator for questions.

[Operator Instructions] First question comes from Neal Dingmann of William Blair.

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 '24. And look, since then, oil has gone from -- diverged between $55 and $87, yet your plan has remained as consistent as ever. So I guess my question is, is there much that would cause that to change any direction, whether it's prices or something else that caused you to diverge from that long-term plan?

Neal, thanks for the question. Yes, we're really happy with the quarter and the outlook for the organization. I'd say as we think about our activity levels, the great thing is, is we've built a really resilient company. And as -- 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.

And so I think our -- like the volatility of our activity program is -- it may be a little muted relative to others because of that resiliency we have in the organization. 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. And so you could see a movement in the program. But with where we're at now and down to levels far, 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. So it's a great thing about having strong subsurface and a strong team and the asset we've built.

Great. Great point. And then just my second on fixed cost, specifically, you and I've always talked about, I know Bakken generally having a bit more fixed cost than -- other is the Permian. But 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 of the variable? Or how are you able to continue to decrease breakeven? Is the Bakken still has some of the fixed cost it does?

Neal, I'd say it's -- it is an organization-wide effort to drive our cost structure as low as we can sort of responsibly get to. And so that includes capital efficiency improvements, that includes operating expense improvements, that includes what we do from a marketing and midstream, so GP&T side. So it's on driving improvement through the business. We think it's absolutely critical.

And 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. And so you see that roll through. Clearly, from an F&D perspective, as I talked in my prepared comments, the move to wider space development, longer laterals has had just a dramatic improvement in our F&D, which is really covering on the capital side.

And then 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. So not just the capital side, but also from an operating expense 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 -- these are run rate type numbers that will carry with us into 2026, and we expect to see improvement on this as we move forward. So anyway, 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.

Next question comes from Oliver Huang out of TPH.

I wanted to start on -- I just wanted to start on organic inventory. As we kind of think about the adds 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 at this year's [ formal program ] goes according to plan?

Oliver, what I'll say is that it's really across the basin that we're seeing this improvement. So it's not like it's 1 specific area. But really, as you think about the -- the 1.3 million acre position we've got is really extensive. And as we have lowered our cost structure and continued to work, I'd say, through 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, materially improving our -- the breakeven on inventory. So some things that we always thought were inventory is just now better inventory than we had before. And then some things before that 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.

So 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 more organic inventory flow into the system. And so we think about this on the -- 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. And so as we're able to have these wells 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 to replace production, and it also has a benefit to us there because we're seeing more production from the base wells as we move forward, which will have lower cutoff rates as we move forward and just have us rethink the whole inventory position. So we're really working all aspects of it, both from a capital and OpEx and a productivity side to get more from the wells that we've got, more from future wells. And it just got a really, I think, bright outlook for our overall inventory position.

Okay. That makes sense. And maybe for my follow-up question. We noticed in the 2026 outlook, the 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? And also, any sort of color on how you all are thinking about GOR trends through the 2030 time frame for your portfolio?

Yes, it's a great observation, Oliver. So you're right, we are moving in. Well, I should say we're actually the -- as we think about the 2026 program, 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. And so it's -- we're not concentrated in a single area.

But as we move more out of the historic core of the well of the basin, we do see a lowering GOR. And so -- and that's a little bit reflected in what you saw for us in Q4 this past year and our expectations through 2026. And so 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. There's nuances around shrinking yields that we get from various [ processes places ] we get and how we account for that in our 3-stream production modeling.

But taking all that into account, we are seeing a little higher cut anticipated in 2026. And broadly speaking, as we -- 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. And as our new production comes online, that will come in with a little bit of a lower GOR relative to the historic production. And so we're trying to balance all that in the projections that we put out there.

Okay. Perfect. That makes sense. So 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?

Yes, I'd say that's a great way to frame it. We don't anticipate seeing really an increase in our gas cut, and it may be that our oil weighting increases, but it will be very slight.

Next question comes from Derrick Whitfield of Texas Capital.

Wanted to lean in on Neal's earlier question with my first question. You guys have done a remarkable job of lowering your breakevens and increasing free cash flow per share over the last several years. Referencing Slide 8, where do you see the greatest levers to further improve the business on the D&C and base production front?

Derrick, I really appreciate the question. I really like Slide 8 of our deck because it just demonstrates the tangible results we've got from a lot of the efforts we've got going on in the organization. And to my earlier comments, we think we have more room to go here.

I'd say we're not -- I'm not focused on any 1 particular area of this. We think we've got opportunity really across every 1 of these buckets. And we're seeing progress on every 1 of these buckets, whether it be production operations opportunities from our base wells, opportunities to lower not just -- I'm going to say this -- from the base production, but we've got workovers that would be included in this as well where we see optimization opportunities. And the continued opportunity to see our cost structure fall as longer -- as more longer laterals flow into the system in our development plans.

And 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. So 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. And while acknowledging you're not highlighting surfactants in your prepared remarks today, clearly one of the larger operators in the basin in Chevron is -- has been palleting 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 it's a great question, Derrick. It's very topical. I'm going to ask Darrin Henke, our COO, to comment on that.

Yes. Great question, Derrick. The -- so we've pumped 19 chemical and surfactant treatments already. And so 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, but we're also looking at adding them on the completions as well, studying that. And we're constantly studying our competitors, be it in the Bakken or other basins as well. And if we're not the first company to be trialing some of these treatments, then we're going to be early adopters as we see that the results merit additional pumping.

So in a nutshell, we 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.

Derrick, I'll just add on to that a little bit, too. We're talking specifically about surfactants here. But I'd say maybe as a broad comment, if you see or read something that someone else is out there trialing, you should assume that we're doing the 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.

So we're doing that as a matter of course. But we also -- we're doing other things as well that we're excited about and thinking can drive potential improvement for us as we move forward. But 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. So we'll continue to work these things and as we see results and have news to share, we'll absolutely be doing that.

Next question comes from Paul Diamond out of Citi.

I want to lean in a bit more on Slide 8. I guess, talk about $30 million to $50 million in annual run rate savings given new negotiations and marketing? I guess, can you talk a bit about the specifics there and I guess the opportunities that you see going forward?

Paul, thanks for the question. This is Michael. Yes, the team has done a great job on the marketing and midstream side. And some of the things that we've seen is this basin is -- has a maturity to kind of its midstream infrastructure kind of throughout the basin. Contracts are -- have been long-term contracts, but the basin has been around for a while. So a lot of those contracts are coming up -- have come up or are coming up. And so as those contracts near their term, we're able to get into new contracts that are at lower cost points, which is fantastic.

So 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, many contracts. So keep watching. I think there -- as Danny kind of mentioned, each of these buckets have room to move. The marketing and the midstream side, no different.

And just 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. So some of that's coming with production improvements, some of that is coming through cost reductions. But overall, just raising kind of the free cash flow profile of the company, not only on a one-term basis but on a long-term basis.

Got it. I appreciate the clarity. And then just a quick follow-up, talking to Slide 15. In guidance, you guys telling about 150 locations in '26. I guess, how do we think about -- you added 300-odd 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?

So clearly, this is something we're going to be really -- this is Danny again. Paul, clearly, this is something we're going to be really focused on. And I think for any 1 year, it may look different. M&A, we're going to be -- as you've seen, we've been very disciplined on this over time. And we're going to pick our spots. And so 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. And that would obviously impact this chart. And then the efforts we've got internally should be continuing to drive sort of organic inventory replacement.

So I think it may be -- the buckets, I think, will be the same. The percentage of any buckets made there for a little year-over-year, and it's just going to depend upon the opportunities we're able to identify as we move forward.

Next question comes from Noah Hungness out of Bank of America.

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. But I guess I was curious, if you could give any color maybe on what the '26 exit decline rate looks like versus maybe the '25 decline rate? .

Yes. I think the decline rates year-over-year broadly look similar on an annual basis. And really, that's kind of how we think about things. And so I don't think there's a whole lot of change as we incorporate. As we said, we may see -- on a longer-term basis, we see maybe a little bit of moderation in decline. Assuming we continue to run a sort of 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. But again, it will be small, very small single-digit percentages in that, but helpful from a reinvestment rate perspective. So 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 was -- were any of your capital activities affected by winter storm Fern in 1Q? And if so, I guess, what does that mean for the timing of capital spend through the year?

Great question. No, I'd say we had -- it's winter in North Dakota. And so winter in North Dakota, you just have to -- the environment that we operate in. So it's something that we're very used to and absolutely plan around. It did impact some of our activity in 1Q, but 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 third quarter and then pull back a little bit in the fourth quarter, and we still expect to see that exact same shape playing out through the year.

So 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. But I'd say nothing significantly unusual for winter in North Dakota. And 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.

And our teams did a fabulous job getting the production back online where we did go off-line on production and getting activity back out. So definitely one of the best in the basin when it comes to recovering from a winter event.

Well said, Darrin.

Next question comes from [ Carlos Escalante ] from Wolfe Research.

This is Carlos on for John. 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 TIL the same amount, but 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 '27. But 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?

Yes. Broadly speaking, Carlos, I appreciate the question. And again, I'll reiterate your comments that we're not guiding to '27 at this point. We're just now coming out with '26. But I will say that -- what we're seeing with our development program is we've got some nice tailwinds to 2027. And so from a capital efficiency perspective, the sort of roll in of the TILs from the capital deployed in 2026, all of which we think will be helpful to a 2027 program. So we feel good about -- I feel very good about what we accomplished in '25. 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.

That's great color, Danny. And then on the second one, and perhaps it's more of a miscellaneous question, just in light of what a lot of your peers are or have been signaling in the Permian Basin as a whole, activity-wise going down the whole. 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. But 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 because you have healthy inventory as you do right now?

Thanks for the question, Carlos. I'll start with sort of the last comment. And 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. And so our inventory that we look at, it's some of the widest space within the basin. It 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. And so a very repeatable development. Very -- our spacing is relatively -- well, actually, I'd say it is conservative with no need to put an adjective around that. So it's conservative space Middle Bakken program, and we've got a ton of it. And so 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 other -- what folks do in and out of basin and see what we can apply of what we've got. So we'll monitor it and we'll respond as would be appropriate, but the great thing is we've got a really deep inventory set with what we've got currently and feel great about our plan.

Next question comes from Nicholas Pope of ROTH Capital.

There are several comments on water kind of disposal optimization in the market [ appization ] line item. And then kind of an uptick on spend in the midstream in 2026, 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 what -- kind of further and what you commented on the late stage, kind of the development that are in place there? Or if anything has materially changed with kind of the field level production of water out there.

Nick, good question. This is Michael. So just thinking about the midstream, and I like the way you kind of characterized that. We talked a little bit earlier that GORs are kind of, call it, 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 they're not quite as many of those.

And so 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. So incrementally, it's not a lot of capital overall, but it is very kind of productive capital for us to spend.

Got it. And so 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. But for capacity for water, I mean, are we -- 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 going to produce?

Yes. 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. And so there is a need to try to get kind of water disposal a bit closer to your wellbores overall. And so that's why there is some ongoing capital spend on the water side. But 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.

Next question comes from Noel Parks out of Tuohy Brothers.

I was wondering, did the full impact of your lateral length extensions get captured in your 2025 reserves?

Yes, we have captured the expectations that we have for the wells that we drilled and the results we've seen. So as you're probably noting, like on the 3-mile wells that we've delivered, we have captured that in our reserves. But as you probably know, we had actually just recently [ TILed ] the 4-mile wells. So that's probably on the early side. So obviously, there might be like 1 or 2 wells on that front, but it's not really fully captured when we think about the full [ PUD ] development. But it's -- yes, it is pretty straightforward from the standpoint that what we saw in the 3-mile results resulted in the type of uplift that we talked about in all of our materials.

Great. I was just curious about how the timing of that worked out. And just a little while ago, you were mentioning that we can consider the inventory to be conservatively spaced. And so much of the focus on the longer laterals, I think, at least for me, has been on how they raise the tier of the maybe outer part of the footprint to make locations viable that wouldn't have been with shorter laterals. But 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 that [ 4 miles ] can introduce into the [ next ]?

No, it's a great question. And I think the answer is, yes, there probably is beneficial implications as we get better at drilling these longer laterals. And I think -- also, we don't talk about it very much because we don't -- 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.

But the combination of longer wells and alternative shape wells, I do think has some implication. And as the 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 where we've got good reservoir contact areas. We think we're effectively draining the reservoir with what we've got now. But where these longer laterals, and maybe more importantly, the alternative shaped wells to 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.

But if you don't have the ability to drill these alternative shaped wells, you may not be able to access that very well. And so the combination of longer laterals and alternatives, I think it's got a beneficial implication to infield development programs. We really haven't quantified that yet. So I'd say that's going to be -- a lot of that would be upside to what we think about now. And as our cost structure on these gets lower, as our ability to execute them gets larger, it probably just gets better from there. But quantifying that, it would be a small piece of our overall inventory as we think about it today, but certainly a nice potential incremental opportunity for us to evaluate and continue to add in.

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.

And 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 lines.

Good morning, ladies and gentlemen, and welcome to the Chord Energy Third Quarter 2025 Earnings Conference Call. [Operator Instructions] This call is being recorded on Wednesday, November 5, 2025. I would now like to turn the conference over to Mr. Bob Bakanauskas. Please go ahead.

Thanks, Anne, and good morning, everyone. This is Bob Bakanauskas and today, we are reporting our third quarter 2025 financial and operational results. We are delighted to have you on the call. I'm joined today by Danny Brown, our CEO; and 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 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 this 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. And with that, I'll turn the call over to our CEO, Danny Brown.

Thank you, Bob. Good morning, everyone, and thanks for joining our call. Last night, we issued our third quarter press release and presentation. The materials covered key strategic, operational and financial details. Over the next few minutes, I plan to highlight a few key items. And after that, we'll open it up for Q&A, where I'll invite other members of the team to provide additional insights. Starting with third quarter results. Chord delivered another consecutive quarter of solid operating performance with free cash flow above expectations and strong returns to shareholders. Adjusted free cash flow for the third quarter was approximately $230 million, and we returned 69% of this free cash flow to shareholders. Notably, after our base dividend of $1.30 per share all incremental capital return was utilized for share repurchases. Since the combination with Enerplus closed last year, Chord has reduced diluted shares outstanding by approximately 11%. Chord's execution and asset performance continued to trend favorably to expectations. Faster cycle times, lower levels of downtime and strong well performance have led us to raise oil volume guidance for the second time this year before including the impacts of XTO.

Chord also continues to drive efficiency across the business. On the drilling and completion side, we brought online 3 new 4-mile wells since our last update. All came in below initial cost estimates and early production data is encouraging. Chord has made tremendous progress on its 4-mile program this year, confirming initial design concepts and continuing to derisk execution. We expedited the program versus initial expectations at the beginning of the year and continue to expect 7 4-mile wells turned in line by year-end. The favorable performance we're seeing increases the likelihood of leaning into the 4-mile program in 2026 and beyond. Given the strong progress we've made year-to-date, we would expect 4-mile wells to be up to 40% of the operated program in 2026. 3-mile wells could make up another 40%, pushing cord towards approximately 80% longer lateral development next year. Additionally, this year, Chord further improved capital efficiency by derisking the execution of various alternate shaped wells. Year-to-date, Coronas drilled 11 and till 8 alternate shape wells. Execution has been strong with costs trending below initial estimates. While alternative shapes will be a small part of the long-term program, they are a useful tool to improve economics in certain PSUs.

Turning to other continuous improvement initiatives. We are pleased to announce progress in improving our marketing cost structure as the team has been working hard to simplify and optimize contracts across oil, gas and water. Slide 7 of our investor presentation shows expected savings of $30 million to $50 million a year. About half of these savings were realized in 2025. Slide 6 shows Chord's overall progress in enhancing free cash flow generation across the organization with core driving $120 million of improvement in 2025 from controllable items, including higher production, lower LOE, less capital and improved marketing costs.

Slide 11 highlights that free cash flow per share has grown over 20% since February. Going back slightly further to when we announced the Enerplus transaction, pro forma free cash flow per share is up more than 35%, all on normalized pricing. That's impressive performance may be even more impressive when considering we preserve the balance sheet along the way. Turning to the XTO transaction. I'm pleased to report that we closed the transaction on October 31, and and as a result, have adjusted fourth quarter production up by 4,000 barrels of oil per day. Additionally, we added capital of $15 million to full year 2025 and in order to begin supporting the resulting higher maintenance production levels in 2026.

In short, we are excited about integrating these high-quality assets. The acquisition is in one of the best areas of the Williston Basin has significant overlap with Chord's existing footprint and supports long lateral development. This is Chord's fifth Williston Basin deal in 5 years and is consistent with our long-term strategic objectives. In addition to the XTO deal, we also added inventory this year through our leasing efforts and smaller track acquisitions. Over the years, Chord has been successful in maintaining its low-cost inventory depth through adopting new technologies and driving efficiency in the base business while supplementing these improvements with opportunistic M&A. Shifting focus to our development activity. Chord continues to plan on bringing in a second frac crew in a few weeks. Chord's cycle times have improved significantly this year, pushing back the start date of this second crew which gave us the opportunity to lower capital by averaging fewer frac spreads versus the original plan, and we accomplished this while raising production expectations twice.

As we look to 2026, our preliminary expectation is maintaining oil volumes of approximately 157,000 to 161,000 barrels per day, while holding E&P capital flat in 2016 versus 2025 and plus approximately $40 million for maintaining the XTO volumes. This would result in total 2026 CapEx of roughly $1.4 billion. To put this in perspective, in early 2024, and the pro forma capital budget to deliver lower production levels was approximately $1.5 billion. In contrast, Chord's preliminary 2026 expectations reflect approximately 4% higher oil volumes for roughly $100 million less in capital. Clearly, Chord's capital efficiency has improved. Commodity volatility remains high, and Chord will continue to monitor conditions closely. We have significant flexibility to reduce activity if macro conditions warrant. However, any decision to adjust activity would reflect a thoughtful patient evaluation and won't be driven by sentiment in any given week. Chord has worked diligently to improve the parts of the business that we can control while maintaining significant downside protection through its operational flexibility and strong balance sheet.

In the spirit of transparency with our stakeholders, we also recently published Chord's 2024 Sustainability Report, which includes performance metrics on a pro forma basis, reflecting the Enerplus combination. Thank you to the team for putting this together as it does a great job discussing our business and highlighting our efforts on emissions, reductions, workforce health and safety, corporate governance, philanthropy and other topics. Chord remains committed to delivering affordable and reliable energy and to do so in a sustainable and responsible manner. The external landscape has fluctuated significantly over my years as an E&P executive but this commitment has always been and will continue to be an important element of Chord strategy. Our goal is to drive continuous improvement in everything we do.

To close, Slide 14 highlights Chord's performance versus peers on a total return basis. As you can see, our long-term performance versus peers has been strong. Importantly, we did this through improving EBITDA and cash generation relative to enterprise value. It did not get much help for multiple expansion. On that note, Today, Chord's valuation remains attractive versus peers despite the long-term equity outperformance. Chord has an established history of strong capital allocation, consistent operations and high cash returns. These positives, coupled with resilience and low-price periods and significant upside potential to the next constructive oil cycle make Chord a unique and attractive investment opportunity. With that, I'll turn the call over to [ Anus ] for questions.

[Operator Instructions] The first question comes from Scott Hanold with RBC.

Danny, I appreciate the framework on 2026. It was really helpful. I'm kind of curious with the success on the 4-mile wells and you're all indicating you may take that up a level next year. when do you all think you'll start really seeing some of the benefits on the capital efficiency side from those wells? Because they do have like relative better capital efficiency, lower decline rates. Is that something that may take a year or 2 to really start driving capital down? And where do you think that could go?

Yes, Scott, I appreciate the question. Yes, so we're really pleased with what we're seeing from a 4-mile perspective. So I'm glad you're bringing that up, and we were happy to communicate that we think it could be a meaningful portion of the overall 26 program. I think we'll see the real benefit of that -- as you get towards the later part of '26 and into '27 is when you'll see that lower decline rate really sort of help be a differential helping factor for us. And so we're pleased with where the '26 plan is shaping up, and I think we're really pleased with how we're setting ourselves up for the out years as well.

Yes. And could you quantify like what could that could do to CapEx in '27, I guess, as part of that?

Yes. I think we're still working through the '26 -- we're giving a soft guidance on '26 now. We'll give formal guidance in February, and we'll give -- we'll look as I know in the past, we've given 3-year guidance, we need to get the XTO incorporated, and we'll talk a little more -- we'll talk a little more in February, but I think too early to comment on '27, except to say that -- as we look at the overall plan, I'm really encouraged about our multiyear outlook, which really strong.

Okay. I appreciate that. And then my follow-up is on the marketing and midstream agreements. Could you give us a sense of like what does this mean for natural gas and specifically maybe NGL differentials as you go into next year. How much do those change from where you are right now? Because obviously, NGL pricing has been challenging. I guess gas price has been challenging to at times. So how much of that's already accrued into the numbers you're seeing today? And how much more benefit do we see next year?

Yes, Scott, this is Richard. Great question. You had seen that we had announced there was about $20 million that was impacting the business in 2025. And that is really related, as you noted, to gas and NGL. And then as we move into next year, that, call it, $40 million at the midpoint would be spread across gas and NGL as well as a little bit of benefit as well as GPT. So it will be spread across the entire business. And I think the other thing to note, and I think you kind of highlighted this, mean gas prices have been pretty volatile throughout 2025, we had a great beginning of the year. And as typical, it typically dips in the middle part of the year and then builds back in the fourth quarter, you've seen some prices bounce back here recently. So that should be helpful tailwind as we move into 2026.

Your next question comes from Derrick Whitfield with Texas Capital.

Congrats on a positive ops update today.

Thanks, Derrick.

Regarding your alternate shaped wells, it's clear that they can positively impact 10% of your long-term inventory based on Slide 20. Perhaps for Danny or Darrin, like how would you guys characterize the cost and execution differences between the alternate and standup equivalents? And any color you can add on location concentration of these alternate shape wells?

So maybe I'll kick off and then turn it over to Darrin for some additional commentary. I think the neat thing about alternate shaped wells for us is we're uniquely positioned, I think, amongst many of our peers that given our 1.3 million acres that spread out really across the totality of the basin, we've got a lot of fairly underdeveloped units where we can do long straight laterals, which we think are going to be the most efficient way for us to sort of enjoy the benefits of longer lateral capital efficiency improvement. And so the bulk of our long laterals will be straight long laterals. But we do have areas within the portfolio that are constrained by historic development and in those areas, these alternate shapes can be helpful. And an example of that may be on the Enerplus acreage we picked up from our -- from the transaction that was really in the core of the basin, but had a lot of legacy development around it, which constrained our ability to go to as far as many long straight as we would have otherwise liked to. So these alternative shapes are a great opportunity to get some of the really significant portion of the economic benefit of long lateral development when you don't have quite the geometry that's quite as conducive as just having sort of the straight geometry available to us. So execution to date has been really, really strong. I've been super pleased with what we're seeing, and I'll ask Darrin, maybe to provide some incremental comments there.

Yes. So we drilled 11 alternate shaped wells year-to-date and 8 of these are online. And we're only seeing just a couple of percentage points like if we drill a 2-mile linked alternate shape well, it's only just a few percentage points more expensive than a straight 2-mile well. So the team has done a great job of reducing the cycle time and not only drilling it, but getting to completed and getting them drilled out. So it's definitely drilling a couple of alternate shaped wells versus drilling 3 traditional wells with definite cost savings there and increase -- improvement in our supply costs for sure.

Great. And for my follow-up, I wanted to focus on Slide 18. Regarding enhanced production uptime and artificial lift optimization what degree of coverage do you guys have in place today? And where could that go over the next couple of years?

Yes. So I think as we think about from a production perspective, there's been a lot of I think really across industry and our organization is probably a microcosm of industry in some respects. There's been a lot of focus on improving our drilling and completions performance over time. And you've seen that roll through and reduce cycle times, improved capital efficiency. We focused on our base production along the way. But as we think about artificial lift, it hasn't gotten the intense focus that drilling and completion activity has historically. And so we think we've got room to optimize. We've got room to optimize this, and we've got it, I think, from a couple of different angles. One is there's new technology out there on artificial lift. We've got close to 5,000 wells in the field. And so we've got -- most of this will end up on rod at the end of the day. But there's some intervening steps on how you get from free-flowing wells to rod wells. There's different types of rods you can use. There are some new thoughts on how you can do some maybe rodless pumping units. And so we're going to see what our opportunity looks like from that perspective. And then there's the automation piece of this that I think is pretty significant.

So thousands of wells that we can get -- that we can improve our automation performance with -- we've done that with a lot of our rods already across, I think, a big portion of the field. And so it's taking this momentum we've built over the past, call it, 18 months or so and just continuing to build on it. But I'll ask Darrin to weigh on this some more.

Yes. So relative to our rod pump wells, artificial intelligence is really controlling all of the parameters as we pump the wells and we're seeing -- starting to see some improvements in run times as well as less downtime, less we're seeing less frequency on the workovers. So hopefully, that's something we can quantify more next year, and we're starting to look at our ESPs, how can we turn those over to artificial intelligence as well to control all the parameters on our electric submersible pumps.

Your next question comes from John Abbott with Wolfe Research.

So the first question is really a longer question is all about production. So -- and the first question is you acquired the XTO assets at the time the deal was announced, you talked about 9,000 BOE per day -- we've acquired the assets. How has that asset performed compared to your initial expectations? And then the follow-up question is really on 2026. You provided the soft guide of about 157,000 to 158,000 barrels per day. It looks like the Street is a tad that higher than that. You do have a tendency to raise production over time. But could you talk about the shape of production in 2026. So those would be my 2 questions.

Thanks for the question, John. Well, so a couple of comments. One, on the XTO transaction. That transaction came with about 9,000 barrels equivalent a day, about 6,000 barrels of oil per day, and we've got that locked in for sort of 2 months of the year, closing on October 31. So hence, the 4,000 barrels of oil per day increase that we pushed through in the numbers we just released. The assets we just closed on it. And I think our expectations and our observations on that asset are very consistent with how we thought about it when we entered into the acquisition discussions in the first place. So nothing but pleased with what we're seeing there. But early days, a nice thing about it is oily production and it's low decline oily production. And so we really like that. That was one of the things we liked about that asset.

With respect to our volumes in 2026. You mentioned $157 million to $158 million. It was -- it's -- our expectation is they are a little higher than that. It's $157 million to $161 million, so call it $159 million at the midpoint. And so that's really what our expectations are as we move forward. From a shape perspective, I think we'll probably see like we often do, probably the strongest production contribution in the middle part of the year with a little bit of cyclicality. So 1Q will be slightly lower. 4Q may be slightly lower with most production coming through in the second and third quarter. But that overall number is going to average, we think, at the midpoint, 159.

Your next question comes from Noah Hungness with Bank of America.

I guess for my first question here, going back to the '26 program, when we're trying to think about total tile wells or till lateral footage. Could you maybe just at a high level, touch on how that compares to the '25 program?

Yes. So appreciate the question, Noah. We'll probably get into all that in February. And when we provide detailed budget outlook for 2026. So generally, at this point in the year, we like to give sort of soft guidance on what our capital and production levels are in aggregate, and we'll get into the details in February.

And then I guess for my second question here, commentary around the formal wells that you guys have put into production so far, sounds really positive. You're seeing full contribution across lateral and a coming under budget. How are you thinking about the EUR and the capital ranges that you've given [indiscernible] today?

Yes. So from an EUR perspective, I'd say what we anticipate is that we'll see, call it, 90% to 100% EUR uplift relative to what we'd see in 2-mile wells. And so we've kind of underwritten the program expecting that there'll be some contribution degradation in that fourth mile. As a reminder, as we've looked at our 3-mile program, we really haven't identified any degradation in the 3-mile program. And so that third mile is contributing just as efficiently as the first 2 miles in our 3-mile program. But to be a little conservative, we've underwritten some degradation in the fourth mile. So we only assume that's 80% contributing. I'll say our first 4-mile well, we're already equivalent to 2 miles to 2 2-mile wells. And so at this point, that, well, it doesn't look like it's seeing much degradation. But again, the overall program, we're underwriting with a little bit of degradation that fourth mile and the economics is still wildly superior to our other development options.

So we're -- we're encouraged by the 4-mile program, the EUR, we think, may be again between 90% to 100% of what you'd see in compare--mile wells. And so a little bit of degradation assumed and we'll have to see what production history proves out over time.

And then on the CapEx, are you still kind of thinking the midpoint of the range, even though the wells so far have kind of come in under budget. I guess when you're saying under budget, is that the midpoint of the range?

Well, so they've come in under our initial expectations, recognizing we had some these were early serial numbers on what our expectations were. So we expected there to be a little learning curve. Are we getting through that learning curve quicker than we thought we might otherwise. And so it's coming inside our expectations, but we feel good about the ranges we put out there previously.

Your next question comes from Oliver Wong with TPH.

For my first question, I was just wondering on TIL for this year. Timing is obviously going to be a factor, but when we're thinking about the stand-alone CORD program today versus the start of the year, you all have been able to essentially hit a similar level for oil on roughly 20 less gross TILs. Just trying to better understand the various drivers with respect to what you all are seeing on operated well productivity versus internal expectations to start the year? And also, if there may have been an increased movement on the non-op side that's allowing you all to pare back a little bit more on the operated side.

Yes. So I'll kick off, and I'll ask others to weigh in. I think it's a great observation. Oliver. We are seeing about 20 fewer TILs this year relative to our original expectations. I will caution that from a drilling and completion standpoint, we haven't seen that same reduction from a drilling and completion standpoint. In fact, we're up a little bit on our drills. We're down slightly on our completions, but the TIL count is coming in lower. And I think the reason we've been able to really raise production guidance twice despite that lower number of TILs is around, one, the wells have performed well. And so we've seen strong performance from our operated program. We got a few of them online a little earlier than we thought, and that's obviously helpful when you talk about annual contribution from a well that's coming online. So that's been helpful. We've seen a little more non-op come through, and we've had great performance from our base production perspective. And so we've seen some lower downtime, which is always great because you're able to -- for very low cost able to deliver better production. And so that -- and that's really due to a lot of the effort that Darrin's team is going to try to optimize our base program where we see, I'd say, fertile ground to do even more. So really, that kind of, I think, bridges the bridges that difference for us.

Okay. That's helpful color. And maybe just for a follow-up question. Just on the marketing optimization. Any sort of color in terms of how we should be thinking about the runway to kind of drive some of that further upside beyond the $30 million to $40 million or so that has been outlined here. And just with respect to some of these recent agreements, were these primarily in the form of a blend and extend? Or were these more in the bucket of just contract roll-offs?

Yes. Great question. If you remember at the beginning of the year, we talked about 3 big buckets of costs that we thought we could go after. And I think the team has done an incredible job on all 3 buckets, and you see that in our presentation where we've outlined that $120 million that Danny talked about earlier of savings from kind of the beginning of the year. And it's in the combination of all 3 buckets, whether it's the production LOE side of the business, whether it's the execution or D&C side of the business, and now you're seeing the fruits of the kind of marketing midstream I think there's continued opportunities on all 3 buckets that we'll continue to push. On the marketing and midstream in particular, one of the things we kind of talked about was a lot of the contracts in the basin were done in 2010 to 2014. A lot of those were 15-year contracts that are kind of coming due over the course of this year as well as the next few years. And so I would say it's a combination. These are a number of smaller deals that add up to some pretty significant value for us, and they will continue to be those deals going forward. Remember, in 2010 to 2014, newer basin, less infrastructure overall, negotiations were difficult from a producer standpoint to get good rates. Today, there's a lot more competition, just a lot more opportunities to optimize there. So team is doing a great job. It's going to be across, I think, a number of deals going forward. But we do continue to see additional opportunities to create good strong win-win situations with our midstream providers as well.

Your next question comes from David Deckelbaum with Cowen.

I wanted to follow up, Danny, just obviously, you've been focused on getting down that $300 million of controllable spend. The marketing agreement goes a long way to getting there. As you think about the progression in other areas as we go into '26 and '27, do you can see that the bulk of them are going to present themselves from the benefits of longer lateral designs or are there more chunky elements such as the marketing agreements that we should be focusing on?

David, it's a great question. I think what we've seen is -- we have strong conviction that we can improve our cost structure across really all elements of our business. And so Michael talked about the 3 buckets that we think about this from a D&C, and operated D&C perspective, a production perspective and then a marketing and midstream perspective. And I think we'll see improvement and are seeing improvement really on all of them. I think we've got some -- at least a slide in the deck that shows some of the different buckets and how that's generated incremental free cash flow for us relative to our expectations at the beginning of the year. We continue to have room to run down this path. We're just getting into the 4-mile program, and so that's going to help us from a D&C perspective, we get all sorts of efforts going on from a production standpoint.

One thing -- we've got -- I mentioned the nearly 5,000 wells we have out in the field earlier, and we've got some really significant workover program that helps make sure that those wells continue to operate efficiently and remain up. We have recently switched over to some software that helps us optimize our scheduling for our workover program that I think could yield significant benefit and that's delivering higher levels of production for lower levels of cost and making sure that we're optimizing that spend that goes into our workover operations. And then in addition, we've talked before about taking some of that same rigor that we apply to our drilling program and looking at sort of best composite times for jobs and can we imply some of that to our workover activities because it's a lot of similar jobs that happen across a bunch of different companies. And so if we can standardize what sort of some of our procedures around that and try and recognize what sort of a perfect job would look like that gives folks something to aspire to and it's amazing if you give folks a goal and something to aspire to how we can get close to achieving it if sometimes surpassing it. So I just think we've got lots of opportunities in different areas of the business, and we're going to see this -- we're going to continue to chew into that cost structure. And could there be chunky items along the way? Of course, there can be, but we're going to be focusing on at all.

I guess leading on that point, as you focus on optimization and you focus on these best practices and better economics, you just pulled up the XTO deal, a small bolt-on, but still meaningful. It seems like the basin is still it's consolidated but fragmented. Would this make you more acquisitive relative to the maybe inefficiencies that you see available out there that you could accrete value back to court holders?

Yes. So David, I think we are sort of inquisitive and acquisitive by nature. We've done 5 deals over the last 5 years. And so we're believers in consolidation. But importantly, that consolidation can't just make us bigger. It has to make us better, too. And so to the degree that we have ability to take sort of differential skills or ability and apply it to other assets in the basin. I think that allows us to be more one, front-footed and maybe proactively reaching out to other parties and then certainly more competitive in any process that we've got because we can just bring more value to bear, which should allow us to be more successful as we look at different opportunities within.

Your next question comes from Kevin MacCurdy with Pickering Energy Partners.

And to piggyback on David's question, you're now the biggest operator in the basin. Have you done the analysis or do you have a view on how your lateral lengths and margins compared to peers? Obviously, this would be in relation to being able to acquire peers and extend their lateral lengths and lower their -- or increase their margins?

So as you'd expect, Kevin, we've got a kind of we benchmark ourselves against others pretty frequently. We like to make sure that, one, it helps us learn from others. And then two, it helps hold ourselves accountable for our performance. But certainly, that also feeds into when we see, I'd say, maybe dislocations to ourselves relative to others, that can present opportunities, and we think about that.

Okay. And then shifting gears a little bit, I wanted to ask around the plans for the Marcellus acreage. Are there any updates on the sale process or maybe even a reconsideration of keeping the asset I mean there's been a pretty hot M&A market in the gas land, especially near the Gulf. Not sure if these dynamics are influencing your thought process on your acreage?

Don't have a lot of update to provide relative to our early comments on Marcellus, Kevin. It is a noncore asset. We've been very vocal about that. We'll look to maximize value from that asset over time. It's a great asset, low friction cost to us on holding it, but it is noncore and we just want to maximize value from it.

Your next question comes from Paul Diamond with Citi Group.

Just a quick 1 on the XTO acreage. Given the need to permit and integrate it, when do you think those start to roll in? When do you think those wells start to roll into a wider program?

I think it's a great question, Paul, and you're right to bring it up. So we will have to get things permitted on that XTO acreage. And so as we think about sort of the new maintenance level of production that probably implies I saw it get incremental activity on legacy core acreage, and then we'll probably start developing that acreage more towards, let's call it, the tail end '26. And so again, we'll give more specifics in February as we give our formal -- as we put our formal budget out there. But that's -- I think that's a reasonable expectation.

And just a reminder, some of the exciting things about that acreage position is it's in the heart of the play. So really good economics, great geology but it's relatively been undrilled. So what that means is that it's really set up for these longer laterals and straight longer laterals, which is fantastic. It also but a lot of our current acreage. And so we have a lot of flexibility to repermit and re space to even get longer laterals and more benefit out of that asset. So super excited about that asset. It will take us a little bit of time, but a very exciting kind of new asset in the portfolio.

Got it. I appreciate the clarity. And just for a quick follow-up on talking about the alternate shape wells, 10% in the addressable inventory, you mentioned some opportunity on the plus acreage. Should we think about that being kind of the concentration of that 10%? Or is it more spread out?

I think it's going to be somewhat spread out, Paul, but certainly, that acreage for areas that have legacy development around it. It lends itself to it. But I wouldn't think of it as an over concentration in that area. But certainly, that area has some pretty good opportunity there.

Your next question comes from Paul Cheng with Scotiabank.

Danny and the team. Two questions, please. I wanted to go back into the alternative shape well. Just curious that you talked about the case is, say, maybe several percent point higher than a strict well. But how about the EU and the production -- what do you see from there? And also then, have you and there's any differences in terms of what tank or location that it will fit better or that it really doesn't matter that the performance on those alternative well about the same? That's the first question. Second question is that in if we're looking at your current dividend yield, you're certainly already quite high. So how your view on dividend growth, what is a proper growth rate for you or that if there's a payout ratio for dividends, is that a target -- what percent of your cash flow you think is appropriate that for you to pay out in dividends. In other words, they're trying to understand from a cash return to investors, how you look at between dividend and buyback?

Yes. Thanks for the questions, Paul. So I'll talk alternate shapes first. As we've talked about slight incremental capital, very slight incremental capital on an alternative shape well relative to a straight well. And really, I think it's just related to the additional lateral footage that we have to drill to turn the well, and so you've got to -- in order to make the turn, you've got some inefficiency in that incremental pipe and incremental drilling time that you've got to put through the reservoir to get the well turned and head it back the other direction. And so really, that's where the incremental capital comes from. EUR expectations, we think the EUR is going to produce essentially what the straight wells produce. And so again, as we get out -- if we did longer laterals, we might assume some sort of degradation at the tail end of the laterals, but not really incrementally relative to what we see from a straight perspective at least at this point. Of course, this is very early days for us in alternative shapes. The great news is, is that from an execution perspective, these have all executed really well. They're certainly more complicated to execute than straight wells. And so the fact that we've executed them all well and gotten fully cleaned out to tow. I think, one, it's good that we're proving that up for an incremental tool in our toolkit to develop some acreage that might not otherwise be able to benefit from long lateral development, and it helps sharpen our skills for the straight wells, which are frankly easier to execute.

So yes, a little bit of incremental capital, but really just associated with the extra drilling time and pipe associated with turning the well. From a dividend standpoint, I'd say -- we think we've got a healthy dividend right now, it's defendable down to low levels of oil price, and it's something we're committed to and is part of the reason why we said it where it was when we did, we wanted to have a strong base dividend but something that was defensible down to low oil price. As we -- our capital allocation philosophy has really been around paying a competitive base dividend, then look at share repurchases. And then for anything incremental, we would look at potentially doing a variable dividend. And so -- but it's really just a capital allocation decision at the end of the day. And so it's something we visit with our board about every quarter. And so we don't have -- clearly, we're not announcing a change to our dividend currently, but it's something we continually evaluate with the Board, but we think the dividend -- the base dividend, we're except now is in a good place. and we'll continue to monitor that and discuss that with the Board as we think about our return of capital program.

And just curious that some of your larger customers that they would tie their dividend growth rate to the per share production growth rate. Do you think this may be applicable to you guys or that this is not the way how you guys because in theory, your per share production growth then that means your underlying cash flow generating capability to grow, so you can afford to have a higher dividend?

I understand the math behind that, Paul, again, I think it's just -- it's a capital allocation decision for ourselves, and it's something we'll continue to discuss with the Board about what we think the right form of return of capital to our shareholders is.

Your next question comes from Jeff Jay with Daniel Energy Partners.

I have kind of a 2 parter as well. But I guess I'm just wondering about the depth of the deployment and the production improvement basket. I mean it seems like maybe you're well down the road with rod pump kind of early days with the workover automation software, maybe nowhere on ESPs, if I heard right, not really sure on gas lift. I guess, is there just a lot of room left to put these technologies to work in the coming year? And I guess my follow-up would just be -- I mean, it seems like they should have a meaningful impact on base production uplift. But I mean, I also wonder if you expect a material impact on maintenance CapEx like going into 2027 and beyond.

Jeff, I think we're -- I appreciate the question, and I'll ask others to weigh in as well after I finish with my comments. I think we are in the early innings here. We've got -- technology has changed so quickly sort of in the backdrop of how we operate. And so you think about the computing power we have available to us now artificial intelligence, machine learning. There were areas we've talked about internally. It used to be, you had to have fiber laid out to different far-flung areas of the field in order to have remote communication. And now you've got Starlink and other opportunities where you don't have to deploy all that capital and you can have the same sort of benefits of being connected, drone technology is coming a long way, so you can sort of eliminate trucks in the field and folks visiting various locations. And so I just think -- I think we've got a lot of opportunity there. We have -- it's not like we've been static in this, and Darrin mentioned the fact that we've got essentially all of our the computer is trying to automate and improve and optimize our rod pumps currently, and that's certainly the majority of our wells -- the overwhelming majority of the wells that are in the field. But we've got lots of other opportunity here as well. And with the speed of change. I just think it's going to be -- we shouldn't underestimate the impact that, that might have. But Darrin, I ask you to have -- give us some incremental thoughts.

Yes, for sure. Danny. One additional thing that we're executing in the field this year is we're converting many of our workover rigs to 24-hour operations. And if you take 2 12-hour days or 2 daylight workover rigs and convert one of those to a 24-hour a day rig, you basically -- that one 24-hour rig does the work of about 2.3 daylight rigs. And so we're definitely starting to see that efficiency and we're early days there. So there'll be more efficiencies in our workover program as we continue to expand our rigs that are working 24 hours a day. We're also studying our ESP and when we convert from electric submersible pumps, to Rod Lift, and we're trying to get more run life out of our ESPs such that we can minimize the number of ESPs a person has to run in a well before you convert to rod lift. And if we can save on ESP run on a well, that's roughly $0.5 million of spend in the future on those wells. And so just tons of opportunities. Danny touched on some. I've mentioned a couple of additional ones. And the team is rolling up their sleeve and just doing tremendous work in the field to optimize run times, minimize the time it takes to work over our wells and get them back online, and it's really helping us reduce our capital program to keep our production flat. Excellent.

Your next question comes from Noel Parks.

I just been thinking about the 4-mile laterals and you mentioned that with the tracers, you've been able to verify that you're getting contribution from the entire wellbore, which is -- and you mentioned earlier that instead of modeling just 80% of that last mile, you might be able to see more consistent contribution than that. So I'm just trying to think of all the implications of -- if these continue to be successful. And so I was wondering, are there any implications for density of your drilling on -- in units, I guess I was sort of tying that to your comments about the rock quality of the XTO acquisition, I'm just thinking. So I was just wondering if along that dimension there was opportunity as well.

Yes, great question, Noel. So when we think about our development plan, it really is I'd say, tailored to the area of the field and the geology in the area of the field that we're in. And so areas that have more hydrocarbon pore volume within the DSU, we may drill put more wells in because we think more wells are necessary in order to get the -- effectively drain the reservoir. And that would be the case in like the historic core of the field and near where the inner plus acreage is and in some ways near where the XTO acreages that we just picked up relative to maybe some of the areas that are further out Western north. So it is a bit tailored to the geology in the area. And so I don't think the longer lateral program necessarily has an impact on density because we'll just drill will drill longer laterals, but they'll still be at the same inter-well spacing, but the interwell spacing is tailored to the area of the field we're in.

Now having said that, we are doing some testing where in some areas, we've put more proppant in and we're doing larger jobs to say, okay, if we do -- if we pump a larger job, we've had a debate. Are we optimized in our well spacing. And so in some areas, we thought maybe 4 wells is the right section -- wells per section or wells per DSU and maybe we can go to 5 wells per DSU. But you have to weigh that if you could do larger completion jobs on the 4 wells within that DSU. You may just as effectively drain the reservoir in that DSU and not have to put an additional well in may turn out that you need that additional well in because you're not able to effectively drain it. So there's some trade-off between the number of wells that you drill and the size and manner in which you complete the well. And so you just have to realize those, there is a relationship between those 2 things. But specifically with the long laterals, I don't think that's really going to have an impact on our inter-well spacing, but the way we complete the wells might.

Got you. And just thinking about the history of development in the play and over the years, different operators in different regions kind of have a different sense of how to realize incremental value where opportunity is. And with all the additional technical tools you're talking about now, is getting to thinking about future consolidation. And as I mentioned before, what's still a pretty fragmented basin. And are we sort of evolving to the point where operators are going to have like maybe more -- a more and more divergent view of how to optimize particular parts of their holdings. And I just wonder if there are implications for that in consolidation down the road. A couple of different people look at different land with different developments still left to do and come to just totally different conclusions about what is and isn't worth a premium. So I don't know if you have any thoughts on that?

Well, I can't -- appreciate the question. The I think for our organization, we like to be a data-driven organization and make decisions based on the data. And what's nice is, is we've got a large we've got a really large data set, just with our own information but also through our non-op information. We get a lot of well data in the basin. So and we review that data and we run analysis on it, and we do a lot of rigorous analysis on it, and we sort of come to the conclusion that we come to it's perfectly conceivable that a different group of people looking at the same data, also running rigorous analysis may come to a different conclusion. And that's okay. And over time, we'll -- but that will provide more -- as we both pursue different paths, that data will also go into the record, and we'll be able to mine that data too and it will help us determine if one of us needs to course correct. So I'll say where we're at right now, we feel really good about what we're doing and how we're developing the field. We're seeing it roll through and improved capital efficiency and better productivity from the wells. And so we're really pleased with what we're seeing in the basin.

There are no further questions on the phone line. I will turn the call back to Mr. Brown for some closing remarks.

Thanks, Anders. Well in closing, at cord, we believe oil and natural gas will remain essential to meeting the world's energy needs. We are proud to deliver that energy safely, reliably and responsibly. Chord's track record of execution and delivery are differentiated. And I thank our employees and contractors for their dedication and look forward to ongoing progress and innovation. The company is well positioned for success and to deliver significant value for our shareholders through commodity cycles. And 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 lines. Have a great day.