Chord Energy Corp (CHRD) 2025 Q4 法說會逐字稿

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. Currently, Chord has 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, one full-time frac crew and one 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)

Neal Dingmann, 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 in 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 we -- as we think about our activity levels, the great thing is we've built a really resilient company. And because of that, we are -- we think we're able to weather through some of these commodity price cycles and still generate really meaningful free cash flow and shareholder returns.

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 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 point. And then just my second on fixed cost, specifically, you and I have always talked about, I know Bakken generally having a bit more fixed cost than other areas of 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 as the Bakken still has some of the fixed cost it does?

Neal, I'd say 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 really -- everyone is focused on driving improvement through the business. We just think it's absolutely critical. And when you produce a commodity, you've got to be -- 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 that we can deliver as we move forward.

Oliver Huang, TPH.

Dan, 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, if this year's 4-mile 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 one specific area. But really, as you think about the 1.3 million acre position we've got is really extensive. And as we have lowered our cost structure and continue 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 our inventory.

So some things that we always thought were inventory, it's just now better inventory than we had before. And then some things before that would have made sense for us to drill now have really compelling returns as we look at the cost structure we're able to apply against it.

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 -- 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 is also about how we operate the wells. And so as we are able to have these wells flow longer over time, have higher production delivery over time and also have a little bit, if you think about our inventory, our overall inventory relative to the amount of production we are making and the inventory to replace production, it also has a benefit to us there because we're seeing more production from the base wells as we move forward, which will have lower cutoff rates as we move forward and just has 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 has 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 processing plants we get and how we account for that in our three-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.

Derrick Whitfield, 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 breakeven 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 one particular area of this. We think we've got opportunity really across every one of these buckets.

And we're seeing progress on every one of these buckets, whether it be production operations opportunities from our base wells, 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 pelleting 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.

Paul Diamond, 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 in 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 one 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.

Noah Hungness, 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.

Carlos Escalante, 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.

Nicholas Pope, ROTH Capital.

There are several comments on water kind of disposal optimization in the market optimization 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 of Bakken and some of the contracts that are in place there or if anything has materially changed with kind of the field level production of water out there?

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.

Noel Parks, 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 one or two 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-milers can introduce into the mix?

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 shape wells can come with the infill drilling is that it may allow us to go back in and capture some reserves that haven't been really effectively drained.

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.