Good morning, everyone, and welcome to the Chord Energy Third Quarter 2025 Earnings Conference Call. This call is being recorded on Wednesday, November 5, 2025. I would now like to turn the conference over to Mr. Bob Bakanauskas. Please proceed.

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 than 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 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 completed 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 and 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 from 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 in 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.

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 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 relatively better capital efficiency and 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. We are very pleased with the progress we are seeing from the 4-mile perspective. I’m glad you mentioned it, and we are happy to share that we believe it could play a significant role in the overall 2026 program. The real benefits will likely become apparent in the latter part of 2026 and into 2027, as the lower decline rate will be a differentiating factor for us. We are satisfied with how the 2026 plan is developing and are optimistic about our positioning for the following years as well.

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

Yes, we are currently providing some preliminary guidance for 2026, with formal guidance slated for February. In the past, we have offered three-year guidance, and we are still working on incorporating XTO into our plans. While it's too early to provide insights on 2027, I am optimistic about our long-term outlook, which appears very strong as we evaluate our overall strategy.

Okay. I appreciate that. And then my follow-up is on the marketing and midstream agreements. Could you give us a sense of what this means 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?

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 a 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, 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. An example of that may be on the Enerplus acreage we picked up 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 conducive. 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 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 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. From a production standpoint, there has been considerable focus on improving our drilling and completion performance throughout the industry, and our organization reflects that in many ways. This focus has led to reduced cycle times and enhanced capital efficiency as we also emphasize our base production. However, artificial lift has not historically received the same level of attention as drilling and completion activities. Therefore, we believe there is potential for optimization in this area from several angles. For one, there is new technology available for artificial lift. We have nearly 5,000 wells in operation, and most of these will ultimately utilize rods. However, there are several steps to transition from free-flowing wells to rod wells, with various types of rods and even new concepts for rodless pumping units that we are exploring. Additionally, there is significant potential in automation. We have thousands of wells where we can enhance our automation performance, and we have already made considerable progress with many of our rods across a substantial portion of the field. We plan to build on the momentum we've generated over the past 18 months. I'll have Darrin provide further insights on this.

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 starting to see some improvements in run times as well as less downtime, 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 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.

Thank you for the question, John. I have a couple of comments regarding the XTO transaction. This deal included approximately 9,000 barrels equivalent per day, with around 6,000 barrels of oil per day, which we have secured for about two months, closing on October 31. This accounts for the 4,000 barrel per day increase reflected in our recent numbers. The assets we acquired align with our initial expectations from when we began discussions for the acquisition. We are pleased with our findings so far, although it is still early. A positive aspect is that it consists of oily production with a low decline rate, which we valued in this asset. Regarding our volumes in 2026, you mentioned 157,000 to 158,000 barrels per day; our expectation is actually slightly higher, around 157,000 to 161,000, so approximately 159,000 on average. We anticipate the strongest production contributions will occur in the middle part of the year, with some cyclicality—first quarter may be slightly lower, and fourth quarter may dip a bit as well, while the bulk of production is expected in the second and third quarters. Overall, we expect the average production to be around 159,000.

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 tilled wells or tilled 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 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 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?

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 are still wildly superior to our other development options. So 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 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.

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?

They have come in below our initial expectations, and we anticipated there would be a learning curve. We are progressing through that learning curve faster than we expected. While it is still below our expectations, we are confident in the ranges we provided earlier.

Your next question comes from Oliver Huang 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 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.

I'll start by noting that we are about 20 fewer TILs this year compared to our initial expectations. However, from a drilling and completion perspective, we haven't experienced the same decline; in fact, we've increased our drilling slightly. While our completions are down a bit, the lower TIL count is noteworthy. Despite this reduction, we've successfully raised our production guidance twice, largely because the wells are performing well. Some wells came online earlier than anticipated, contributing positively to our annual production. We've also seen a slight increase in non-operated performance and strong results from our base production, which has been aided by reduced downtime. This low downtime allows us to achieve better production at minimal cost. Much of this improvement is thanks to the optimization efforts from Darrin’s team, which we see as having further potential for growth. This effectively explains the discrepancy we’re observing.

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 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 the 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 TD 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 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?

It's a great question. We believe strongly that we can enhance our cost structure across all aspects of our business. Michael mentioned three key areas we focus on: drilling and completion, production, and marketing and midstream. We are already seeing improvements in all these areas. There's a slide in our presentation that illustrates how these improvements have generated additional free cash flow beyond our expectations at the beginning of the year. We still have opportunities to make further progress. We're just starting the 4-mile program, which will be beneficial for drilling and completion. We also have significant efforts underway in production, including nearly 5,000 wells in the field and an extensive workover program to ensure those wells operate efficiently. Recently, we adopted software to optimize scheduling for our workover program, which we believe will lead to higher production levels at lower costs while effectively managing our expenditures in this area. Additionally, we aim to apply the same rigor we use in our drilling program to our workover activities, looking for best practices that can be standardized across various companies. By setting clear goals, we can motivate our teams to reach or even exceed those targets. We have many opportunities across different parts of the business and will continue to address our cost structure. While there may be some larger challenges along the way, we are committed to maintaining our focus on these areas.

As you concentrate on optimization and implement best practices for better economics, you've recently completed the XTO deal, which, while small, is still significant. The basin remains consolidated yet fragmented. Does this position you to pursue more acquisitions given the inefficiencies you observe that could create value for Chord 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 the basin. So in short, yes, I think it positions us well in a consolidating environment.

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

To follow up on David's question, as the largest operator in the basin, have you conducted any analysis or formed an opinion on how your lateral lengths and profit margins stack up against your competitors? This would be relevant when considering acquiring other companies, extending their lateral lengths, and improving their profit margins.

So as you'd expect, Kevin, we've got to 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 relative to ourselves and others that can present opportunities, and we think about that.

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 question about the XTO acreage. Considering the need to permit and integrate it, when do you expect those wells to start coming into the lateral program?

I think it's a great question, Paul, and it's important to address. We will need to obtain permits for that XTO acreage. Considering the new maintenance level of production that this likely implies, I foresee increased activity on legacy Chord acreage. We will probably begin developing that acreage more towards the end of 2026. We will provide more details in February when we present our formal budget. But 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 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.

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?

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.

I have two questions. First, I want to revisit the alternative shape well. You mentioned that the costs are potentially several percentage points higher than a strip well. What can you tell me about the estimated ultimate recovery and production? Are there any differences in performance based on county or location, or is it consistent across the board? My second question is regarding your current dividend yield, which is already quite high. What is your perspective on dividend growth? What would be an appropriate growth rate or payout ratio for dividends? How much of your cash flow do you consider suitable to allocate to dividends? Essentially, I’m looking to understand how you balance cash returns to investors between dividends and buybacks.

Thank you for the questions, Paul. I'll start with alternate shapes. As we mentioned, there’s a slight increase in capital for an alternate shape compared to a straight well, primarily due to the additional lateral footage needed for the well's curve. This requires more drilling and pipe to navigate the reservoir, which leads to the added capital costs. Regarding our EUR expectations, we anticipate that the EUR will yield similar results to the straight wells. If we extend the laterals, we might experience some degradation at the end, but not significantly compared to the straight wells, at least for now. It's still early for us with alternate shapes, but the positive news is that they have been executed well. Although these wells are more complex than straight ones, our successful execution and full cleanouts demonstrate their viability as a development tool for acreage that may not be suited for long lateral drilling, while also enhancing our expertise for the easier straight wells. So, while there is a bit of increased capital involved, it mainly stems from the additional drilling time and pipe needed for the well turns. From a dividend perspective, we believe our current dividend is strong and sustainable even at low oil prices, which is why we established it as we did. Our capital allocation strategy focuses on maintaining a competitive base dividend, then considering share repurchases, and for any excess, potentially a variable dividend. We review this matter with our Board every quarter. Right now, we are not announcing any dividend changes but will continue to evaluate it alongside the Board. We feel confident that our base dividend is in a good position and will keep monitoring and discussing it as we plan our return of capital program.

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 grows, so you can afford to have a higher dividend?

I understand the reasoning behind that, Paul. Ultimately, it's a decision regarding how we allocate our capital, and we will continue discussing with the Board what we believe is the appropriate way to return capital to our shareholders.

Your next question comes from Geoff 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 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 going into 2027 and beyond.

So Jeff, I appreciate the question. I think we are still in the early stages of this. Technology has evolved so rapidly in terms of how we operate. When considering the computing power now available, along with artificial intelligence and machine learning, we see several areas we've been discussing internally. Previously, you needed fiber laid out in distant areas for remote communication. Now, with options like Starlink, you can achieve similar connectivity without having to invest heavily in infrastructure. Additionally, advancements in drone technology can reduce the need for trucks in the field and site visits. There is a lot of opportunity ahead of us. We haven’t been stagnant in our progress; as Darrin mentioned, we’re working on automating and optimizing our rod pumps, which represent the vast majority of our wells. There are numerous other opportunities as well, and given the pace of change, we shouldn't underestimate the potential impact. Darrin, please share your thoughts on this.

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 one of those to a 24-hour 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 sleeves 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.

Your next question comes from Noel Parks.

I've been considering the 4-mile laterals, and you noted that with the tracers, you've confirmed contributions from the entire wellbore. You also mentioned that instead of modeling just 80% of the last mile, there may be potential for more consistent contributions. I'm trying to think about the implications of this if these methods remain effective. Are there any effects on the density of your drilling in certain units? I'm linking this to your comments about the rock quality from the XTO acquisition and wondering if there might be opportunities in that area as well.

Yes, that's a great question, Noel. When we consider our development plan, it is specifically tailored to the field and its geology. In areas with a higher hydrocarbon pore volume within the DSU, we may opt to drill more wells to effectively drain the reservoir. This is particularly true in the historic core of the field and near our Enerplus acreage, as well as close to the XTO acreage we've recently acquired, especially compared to regions further west or north. The plan is adjusted based on the geological characteristics of each area. I don’t believe the longer lateral program will impact well density since we will maintain the same inter-well spacing, which is customized for the specific area. However, we are conducting tests in some locations where we've increased the amount of proppant and are considering larger completion jobs. We have debated whether our well spacing is optimized, and while we initially thought that four wells per section or per DSU was appropriate, there might be cases where five wells could be feasible. It's important to balance this against the potential of completing larger jobs with the existing four wells to ensure effective reservoir drainage without needing to add an extra well. There is a trade-off between the number of wells drilled and how we complete them. Ultimately, while longer laterals may not change our inter-well spacing, they could influence our completion strategy.

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 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 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?

I appreciate the question. For our organization, we strive to be data-driven and base our decisions on the data we have. We possess a large data set that includes both our own information and external data, which gives us valuable insights from the basin. We analyze this data rigorously and draw our conclusions. It's possible that another group analyzing the same data might arrive at different conclusions, and that’s acceptable. Over time, as we pursue different strategies, the data collected will enrich our understanding and help us identify if adjustments are needed. Currently, we feel very optimistic about our approach and progress in developing the field. We are witnessing improvements in capital efficiency and well productivity, which makes us very pleased with the outcomes 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, 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.

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.