Chord Energy Corporation (NASDAQ:CHRD) Q3 2025 Earnings Call Transcript

Chord Energy Corporation (NASDAQ:CHRD) Q3 2025 Earnings Call Transcript November 5, 2025

Operator: 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.

Bob Bakanauskas: Thanks, Anes, 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; 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.

Daniel 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 Chord 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, Chord has drilled 11 and tilled 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 Chord 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 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 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 ’26 versus 2025 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, 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’s 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 Anes for questions.

Q&A Session

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

Scott Hanold: 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 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?

Daniel Brown: 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.

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

Daniel Brown: Yes. I think we’re still working through the ’26 — we’re giving 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 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 looks really strong.

Scott Hanold: 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 too 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?

Richard Robuck: 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 LOE 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, I 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.

Operator: Your next question comes from Derrick Whitfield with Texas Capital.

Derrick Whitfield: Congrats on a positive ops update today.

Daniel Brown: Thanks, Derrick.

Derrick Whitfield: 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?

Daniel Brown: 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 straights 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.

Darrin Henke: 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 them 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.

Derrick Whitfield: 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?

Daniel Brown: 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.

Darrin Henke: 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.

Operator: Your next question comes from John Abbott with Wolfe Research.

John Abbott: So the first question is really a longer — question is all about production. So the first question is you acquired the XTO assets, at the time the deal was announced, you talked about 9,000 BOE per day. You’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 bit 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.

Daniel Brown: 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 157,000 to 158,000. It was — it’s — our expectation is they are a little higher than that. It’s 157,000 to 161,000, so call it 159,000 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, 159,000.

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

Noah Hungness: I guess for my first question here, going back to the ’26 program. When we’re trying to think about total tilled wells or tilled lateral footage, could you maybe just at a high level, touch on how that compares to the ’25 program?

Daniel Brown: Yes. So appreciate the question, Noah. We’ll probably get into all that in February 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.

Noah Hungness: And then I guess for my second question here, commentary around the 4-mile wells that you guys have put into production so far, sounds really positive. You’re seeing full contribution across lateral and they’re coming under budget. How are you thinking about the EUR and the capital ranges that you’ve given for 4-mile laterals today?

Daniel Brown: 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 two 2-mile wells.

And so at this point, that well 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 — in two 2-mile wells. And so a little bit of degradation assumed and we’ll have to see what production history proves out over time.

Noah Hungness: 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?

Daniel Brown: 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.

Operator: Your next question comes from Oliver Huang with TPH.

Hsu-Lei Huang: 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 Chord 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.

Daniel Brown: 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 has gone 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 that difference for us.

Hsu-Lei Huang: 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?

Michael Lou: 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.

Operator: Your next question comes from David Deckelbaum with TD Cowen.

David Deckelbaum: 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 conceive 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?

Daniel Brown: 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, 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. And 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’ve got 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 a 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 all this — for our workover program that I think could yield significant benefit and us 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 apply 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 it all.

David Deckelbaum: I guess leading on that point, as you focus on optimization and you focus on these best practices and better economics, you just pulled off 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 Chord holders?

Daniel Brown: 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 the basin. So in short, yes, I think it positions us well in a consolidating environment.

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

Kevin MacCurdy: 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?

Daniel Brown: 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.

Kevin MacCurdy: 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?

Daniel Brown: 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.

Operator: Your next question comes from Paul Diamond with Citi Group.

Paul Diamond: Just a quick one 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 the lateral program?

Daniel Brown: 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 Chord 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.

Michael Lou: 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 abuts a lot of our current acreage. And so we have a lot of flexibility to repermit and respace 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.

Paul Diamond: 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 Enerplus acreage. Should we think about that being kind of the concentration of that 10%? Or is it more spread out?

Daniel Brown: 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.

Operator: Your next question comes from Paul Cheng with Scotiabank.

Paul Cheng: Two questions, please. I want to go back into the alternative shape well. Just curious that you talked about the cost is, say, maybe several percent points higher than a strip well. But how about the EUR and the production? What do you see from there? And also that have you found there’s any differences in terms of what county 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 is 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 dividend, is that a target? What percent of your cash flow you think is appropriate for you to pay out in dividend? In other words, trying to understand from a cash return to investor, how do you look at between dividend and buyback?

Daniel Brown: Thanks for the questions, Paul. So I’ll talk alternate shapes first. As we talked about slight incremental capital, very slight incremental capital on an alternate 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 turn — 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. And of course, this is very early days for us on alternate shapes. The great news 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 toe, 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 that’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 set 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 where it’s set 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.

Paul Cheng: Danny, just curious that some of your larger customers that they would tie the dividend growth rate to their 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 look at it? Because in theory, as your per share production growth then that means your underlying cash flow generating capability grow, so you can afford to have a higher dividend?

Daniel Brown: 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.

Operator: Your next question comes from Geoff Jay with Daniel Energy Partners.

Geoff Jay: I have kind of a 2-parter as well. But I guess I’m just wondering about the depth of the deployment in 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 this 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.

Daniel Brown: So 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 both 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’d ask you to have — give us some incremental thoughts.

Darrin Henke: 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 day or 2 daylight workover rigs and convert it — 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 1 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.

Operator: Your next question comes from Noel Parks.

Noel Parks: 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 was trying to think of all the implications of the — if these continue to be successful. And so I was wondering, are there any implications for density of your drilling in units? I guess I was sort of tying that to your comments about the rock quality of the XTO acquisition and just thinking — so I was just wondering if along that dimension, there was opportunity as well.

Daniel Brown: 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 — 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 Enerplus acreage is and in some ways, near where the XTO acreage is that we just picked up relative to maybe some of the areas that are further out west or north. So it is a little 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 — we’ll 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 per 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. It may turn out that you need the additional well in because you’re not able to effectively drain it. So there is 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.

Noel Parks: 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, it’s getting me thinking about future consolidation as was 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?

Daniel Brown: 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 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 real data in the basin. So — and look — 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 conclusions 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 we feel — 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 improve capital efficiency and better productivity from the wells. And so we’re really pleased with what we’re seeing in the basin.

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

Daniel Brown: Thanks, Anes. Well in closing, at Chord, 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.

Operator: 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.