Chord Energy Corporation (NASDAQ:CHRD) Q4 2025 Earnings Call Transcript

Chord Energy Corporation (NASDAQ:CHRD) Q4 2025 Earnings Call Transcript February 26, 2026

Operator: Good morning, ladies and gentlemen, and welcome to the Chord Energy Corporation fourth quarter 2025 earnings conference call. Following the presentation, we will conduct a question-and-answer session. At this time, all lines are in a listen-only mode. If at any time during this call you require immediate assistance, please press 0 for the operator. This call is being recorded on Thursday, February 26, 2026. I would now like to turn the conference over to Bob Bakanauskas, Vice President of Investor Relations. Please go ahead.

Bob Bakanauskas: Thanks, Josh, and good morning, everyone. This is Bob Bakanauskas. Today, we are reporting fourth quarter 2025 financial and operational results. And we are delighted to have you on the call. I am joined today by Danny Brown, our CEO; Michael H. Lou, our Chief Strategy Officer and Chief Commercial Officer; Darrin J. Henke, our COO; Richard N. 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 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-Ks 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. I will now turn the call over to our CEO, Danny Brown. Thanks, Bob. Good morning, everyone, and thanks for joining our call.

Danny Brown: Last night, we issued our fourth quarter and year-end results and our updated investor presentation. The materials cover key strategic, operational, and financial details, along with our 2026 outlook. I plan on highlighting a few key points, then we will open it up for Q&A. So, looking back at 2025, in summary, it was an exceptional year for Chord Energy Corporation. We continued to improve the business, evolving our development program, driving efficiencies, and enhancing free cash flow. Chord Energy Corporation consistently delivered results that exceeded expectations, while improving the quality and depth of our inventory and enhancing profit margins, yielding significant incremental free cash flow. Looking specifically at volumes and capital, through their commitment and dedication, the team was able to deliver higher production while capital came in below our expectations.

My sincere thank you to all of our employees who have positioned us for continued success. 2025 oil volumes exceeded original guidance by more than 1,000 barrels per day, while capital came in approximately $60,000,000 lower. Since combining with Enerplus in 2024, Chord Energy Corporation has lowered its capital spending nearly $100,000,000 while delivering 6,000 barrels per day more oil production. Slide eight shows Chord Energy Corporation drove $160,000,000 of free cash flow improvement in 2025 from controllable items, including less capital, lower LOE, lower production taxes, lower G&A, and improved marketing costs. Importantly, the $160,000,000 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 Energy Corporation 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 six shows that since 2021, Chord Energy Corporation 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 Energy Corporation 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 Energy Corporation 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 $175,000,000, substantially exceeding expectations, and we returned approximately 50% of this amount to shareholders.

After our base dividend of $0.30 per share, all incremental capital return was utilized for share repurchases. As we look forward to 2026, Chord Energy Corporation’s plan builds upon last year’s success and remains focused on optimizing capital allocation, generating strong returns, and improving continuously. Last year, Chord Energy Corporation set a goal of converting 80% of its inventory to long laterals. I am happy to report that we achieved that goal by year-end 2025, which was earlier than expected. Chord Energy Corporation’s operational improvements and move to longer laterals have significantly lowered our cost of supply. Slide 15 highlights Chord Energy Corporation’s inventory improvement in 2025, replacing our low breakeven inventory mostly through improvement of the organic portfolio but also through select M&A.

As you can see, we had tremendous success, including conversion to four-mile laterals, while also driving capital and operating costs lower, and it is a testament to the hard work and dedication of our team. In addition, Chord Energy Corporation lowered the weighted average breakeven of its inventory by more than 10% through several efforts, and we have 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 Energy Corporation 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 spent—essentially, the inverse of an F&D calculation—you can see the 2026 program is more efficient than 2025.

Additionally, Chord Energy Corporation’s future F&D cost on a company level has trended 22% lower over the past few years, clearly demonstrating that things are going in a positive direction. And speaking of 2026, despite some severe weather we have seen in North Dakota to begin the year, Chord Energy Corporation’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 $1,400,000,000. From an activity standpoint, we are currently running five rigs, split fairly evenly between three- and four-mile wells, and one full-time frac crew, with the spot crew scheduled to drop around the end of the summer.

We expect approximately 80% of TILs will be longer laterals. At benchmark prices of $64 per barrel of oil and $3.75 per MMBtu of natural gas, we expect to generate approximately $700,000,000 of free cash flow in 2026. So in closing, Chord Energy Corporation 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 have built: a scaled and resilient organization with low decline, significant low-cost inventory, and very attractive exposure to the next crude upcycle, while generating strong free cash flow and shareholder returns in the current commodity price environment.

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

Q&A Session

Operator: If you are using a speakerphone, please lift the handset before pressing any keys. Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you wish to decline from the polling process, please press the star button followed by the number two. You will hear a prompt that your hand has been raised. One moment for your first question. First question comes from Neal Dingmann of William Blair. Please go ahead.

Neal Dingmann: My question is just on the long-term plan. It is really interesting. You guys were early putting this out, I think, if I recall back in early 2024, and since then, oil has diverged between $55 and $87. 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 is prices or something else that caused you to diverge from that long-term plan?

Danny Brown: Hey, Neal. Thanks for the question. We are really happy with the quarter and the outlook for the organization. I would say as we think about our activity levels, the great thing is we have built a really resilient company, and because of that, we think we are 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 the volatility of our activity program may be a little muted relative to others because of that resiliency we have in the organization. From a capital allocation decision-making standpoint, 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 perspective?

And so you could see a movement in the program, but with where we are at now and down to levels far lower than where we are trading currently, we feel really happy with the plan, the free cash flow generation, and the shareholder returns that we have got.

Neal Dingmann: 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 is definitely notable when you look at your breakeven cost. 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 are 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 breakevens, as the Bakken still has some of the fixed cost it does?

Danny Brown: Neal, I would say it is an organization-wide effort to drive our cost structure as low as we can responsibly get to. That includes capital efficiency improvements. That includes operating expense improvements. That includes what we do from a marketing and midstream, so a GP&T side. So it is really everyone focused on driving improvement through the business. We just think it is absolutely critical. And when you produce a commodity, you have to make sure that you are focused on your margins, and we are very keenly focused on our margins. The great thing is that we have, I think, built organizationally tremendous momentum around this, and we have seen success 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 as an organization.

And then we highlight in our investor presentation the $160,000,000 of run-rate free cash flow improvement we saw in 2025, which is really covering on the capital side in our F&D, and we are very focused on continuing to improve. 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 there is a lot of excitement in the organization around it, and I think we have got more that we can deliver as we move forward.

Neal Dingmann: Well said. Thank you, Bob.

Danny Brown: Thanks, Neal.

Operator: Next question comes from Oliver Huang of TPH. Please go ahead.

Oliver Huang: Good morning, Danny and team, and thanks for taking the time. 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 has been highlighted if this year’s four-mile program goes according to plan?

Danny Brown: Oliver, what I will say is that it is really across the basin that we are seeing this improvement. So it is not like it is one specific area, but really as you think about the 1,300,000 acre position we have, it is really extensive. And as we have lowered our cost structure, we have just really been able to continue to work to really refine and improve our inventory position, materially improving the breakeven on our inventory and the geometry of our development program as well as incorporating some new assets we have got into the development program. So some things that we always thought were inventory are just now better inventory than we had before, and then some things before that would not have made sense for us to drill now have really compelling returns as we look at the cost structure we are able to apply against it.

So it is across the basin. As we continue to improve the business as we move forward, I have no doubt that we will continue to see organic inventory flow into the system. We think about this largely on the upfront side, and I think it is common to think about this from your upfront capital costs, which is important, and we have 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, it also has a benefit to us there because we are seeing more production from the base wells and the inventory to replace production as we move forward, which will have lower cutoff rates as we move forward and just have us rethink the whole inventory.

We are really working all aspects of it to get more from the wells that we have got, more from future wells, both from a capital and the OpEx and a productivity side, and it just has a really bright outlook for our overall inventory position.

Oliver Huang: Okay. That makes sense. Thanks for that detail. 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 timeframe for your portfolio?

Danny Brown: Yes. It is a great observation, Oliver. So you are right. As we think about the 2026 program, broadly, it is activity around the basin. We are not concentrated in a single area, but it has got a little bit more of a weighting over to the western side of the portfolio. As we move more out of the historic core of the basin, we do see a lowering GOR, and that is reflected a little bit in what you saw for us in 2026. As you would expect, we are always monitoring the performance of our wells. We are monitoring where our specific development activity is anticipated to be. There are nuances around shrinking yields that we get from various processes, plates we get, and how we account for that in our three-stream production modeling.

Broadly speaking, as we look at the wells in the core of the basin, we expect their GORs to continue to increase, but they will be increasing on a declining base. As our new production comes online, that will come in with a little bit of a lower GOR relative to the production. We are trying to balance all that in the projections that we put out there.

Oliver Huang: Perfect. That makes sense. So as we are kind of thinking through the next few years, maybe just very minimal increases to the oil cut is probably a good starting point.

Danny Brown: Yes. I would say that is a great way to frame it. We do not anticipate seeing an increase in our gas cut, and it may be that our oil weighting increases, but it will be very slight.

Operator: Next question comes from Derrick Lee Whitfield of Texas Capital. Please go ahead.

Derrick Lee Whitfield: Good morning, all. Great update today. Wanted to lean in on Neal’s earlier question with my first question. You guys have done a remarkable job of lowering your breakevens and increasing free cash flow per share. Referencing slide eight, where do you see the greatest levers to further improve the business on the D&C and base production front over the last several years?

Danny Brown: Hey, Derrick. Really appreciate the question. I really like slide eight of our deck because it just demonstrates the sort of tangible results we have got from a lot of the efforts we have going on in the organization. I would say I am not focused on any one particular area of this. We think we have got opportunity really across every one of these buckets, and we are seeing progress on every one of these buckets, whether it be production operations, opportunities from our base wells, opportunities to lower not just where we see optimization opportunities from the base production, but we have got workovers that would be included in this, and the continued opportunity to see our cost structure fall as more longer laterals flow into the system in our development plans.

One of the things I know about drilling and completions is as we get more of these under our belt, our performance on them will get better. We have 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 eight in every one of them.

Derrick Lee Whitfield: That is great, Danny. And thinking about the use of surfactants in new well completions and for workover operations. Billy, one of the larger operators in the basin in Chevron is acknowledging surfactants in prepared remarks today. How are you guys thinking about the use of surfactants in boats?

Darrin J. Henke: Yeah. Great question, Derek. It is very top of mind. We are focused heavily on the production side relative to the chemicals and surfactants at this point, but we are also looking at adding them on the completions as well, studying that. We have pumped 19 chemical and surfactant treatments already, and we are evaluating those results. As we get additional results throughout the year, we will, of course, report back on those. We are constantly studying our competitors, be it in the basin or other basins as well. If we are not the first company to be trialing some of these treatments, then we are going to be early adopters as we see that the results merit additional pumping. So in a nutshell, we have pumped a number of jobs already.

We are studying the results of those jobs, and of course, look forward to success with those. There will be more of those down the road. We have thousands of wells that we could do that on potentially, nearly 5,000 wells PDP based.

Danny Brown: Hey, Derek. I will just add on to that a little bit too. We are talking specifically about surfactants here, but I would say maybe as a broad comment, if you see or read something that someone else is out there trialing, you should assume that we are doing the same thing in here. Either we are already doing it or we are quickly picking up that same information and looking to trial it internally. We are doing that as a matter of course, but we also know we are doing other things as well that we are excited about and think can drive potential improvement for us as we move forward. But we have 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 will continue to work these things, and as we see results and have news to share, we will absolutely be doing that.

Derrick Lee Whitfield: Alright. Fair enough. Great update to you guys.

Operator: Next question comes from Paul Michael Diamond of Citi. Please go ahead.

Paul Michael Diamond: Thank you. Good morning. I was wondering a bit more on slide eight. And let us talk about $30,000,000 to $50,000,000 in annual run-rate savings given new negotiations in marketing. Can you talk a bit about the specifics there and, I guess, the opportunity set you see going forward?

Michael H. Lou: Hey, Paul. Thanks for the question. This is Michael. The team has done a great job on the marketing midstream side, and some of the things that we have seen is this basin has a maturity to its midstream infrastructure throughout the basin. Contracts have been long-term contracts, but they have been around for a while. So a lot of those contracts have come up or are coming up. As those contracts near their term, we are able to get in new contracts that are at lower cost points, which is fantastic. The teams are continuing to look at that, and I think we still have additional opportunity on that side. It really spans across oil, gas, and water, and really throughout the basin across many, many contracts. Keep watching.

I think, as Danny mentioned, each of these buckets have room to move. The marketing and midstream side is no different. You can hear the excitement from the team on this. Really, it is corporate-wide, and what I love about it is it really shows the commerciality that our whole teams are looking at in terms of not only reducing costs, but really just getting better and more efficient across the organization as a whole. Some of that is coming with production improvements, some of that is coming through cost reductions, but overall, just raising the free cash flow profile of the company not only on a short-term basis, but on a long-term basis.

Paul Michael Diamond: Got it. Appreciate the clarity. And then just a quick follow-up. Talking to slide 15, you added 300-odd last year through a combination of organic acquisitions and then the ground game. In guidance, you guys plan on TILing about 150 locations in 2026. I guess how do we think about you breaking down organic versus M&A? Should we think about that breakdown being somewhat similar? Is that a reasonable trend? Or was that an outlier year?

Danny Brown: Paul, clearly, this is something we are going to be really focused on. And I think, for any one year, it may look different. M&A, as you have seen, we have been very disciplined on this over time. We are going to pick our spots. When we see something that makes sense for us to do from an M&A perspective, when we think we will be a better organization on the back end of it, you may see us do something like that, and that would obviously impact this chart. Then the efforts we have got internally should be continuing to drive organic inventory replacement. So I think the buckets will be the same. The percentage of any buckets may differ a little year over year, and it is just going to depend upon the opportunities we are able to identify as we move forward.

Operator: Next question comes from Noah B. Hungness of Bank of America. Please go ahead.

Noah B. Hungness: Good morning. I wanted to maybe lean on the 2026 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 2026 exit decline rate looks like versus maybe the 2025 decline rate.

Danny Brown: Yes. I think the decline rates year over year broadly look similar on an annual basis, and really that is how we think about things. I do not think there is a whole lot of changes we incorporate. As we have said, on a longer-term basis, we may see a little bit of moderation in decline, assuming we continue to run a 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. It is a tailwind that we have got but not a huge tailwind, at least not right now.

Noah B. Hungness: And then for my second question, could you maybe talk about was any of your capital activities affected by Winter Storm Fern in 1Q? And if so, what does that mean for the timing of capital spend through the year?

Darrin J. Henke: Yeah. Great question. No. I would say it is winter in North Dakota, and the program looks pretty similar to what our expectations were last fall. Our teams did a fabulous job getting production back online where we did go offline on production and getting activity back out. We are definitely one of the best in the basin when it comes to recovering from a winter event.

Noah B. Hungness: Well said, Darren. No. That is helpful color. Thank you.

Operator: Next question comes from Carlos Escalante from Wolfe Research.

Carlos Escalante: Hey, good morning team. This is Carlos on for John. Thank you for having us. First question, I would like to lean on what you are doing with the longer laterals. It seems to us that as you drill in 2026 and spud a lot of those, but you do not TIL the same amount in 2027, meaning capital, there is a carryover effect in your capital efficiency in 2027. Obviously, you are not guiding to 2027. But can you perhaps give us a sense of capital efficiency as a whole? On order of magnitude, how would you guide to 2027?

Danny Brown: Yep. Broadly speaking, Carlos, I appreciate the question. Again, and I will reiterate your comment that we are not guiding to 2027 at this point. We are just now coming out with 2026. 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. We are really pleased with what we are seeing in 2025. We feel very good about what we accomplished for 2026. We have got some nice tailwinds with our development program, which we think will be helpful to the 2027 program.

Carlos Escalante: Operators have tried out for type oil development optionality. I mean, obviously, it is a fundamentally different play than the Permian Basin with less stack optionality. But just wondering if there is anything that you can highlight to us, remind us what the optionality is, and also acknowledging that you do not need this today because you have a healthy inventory as you do right now.

Danny Brown: Thanks for the question, Carlos. I will start with the last comment. The great thing about our program is we think we have got a lot of really good inventory in front of us. It is a very repeatable Middle Bakken program. The Bakken delivery from a well has the lowest standard deviation of delivery from any Lower 48 basin out there, and so it is very repeatable development. Our spacing is conservative, with no need to put an adjective around that. It is conservative-spaced Middle Bakken program, and we have got a ton of it. We have a great inventory picture for the organization. Obviously, we are aware of the full column that sits underneath our acreage position there. We are watching what others do. We watch what folks do in and out of basin, and we will respond as would be appropriate. But the great thing is we have a really deep inventory set with what we have got currently and feel great about our plan.

Operator: Next question comes from Nicholas Pope of Roth Capital. Please go ahead.

Nicholas Pope: Good morning. There are several comments on an uptick on spend in the midstream in 2026, mostly focused on water disposal. In the market optimization line item, water disposal optimization, curious if there is anything that has changed with the water production out of the wells, or if this is just kind of further what you comment on the late stage of the development of Bakken and some of the contracts that are in place there? Or if anything has materially changed with the field-level production of water out there.

Michael H. Lou: Hey, Nick. Good question. This is Michael. So just thinking about the midstream, and I like the way you kind of characterize that. We talked a little bit earlier that as we move into areas that have lower GORs, those areas also have slightly higher water. I would say the water systems overall are more mature, but there are not quite as many of those as oil and gas side. As we talked about midstream deals earlier, oil and gas side has kind of more mature systems overall, especially on the oil and gas. The water systems, we are talking about a lot of call flattening in the basin. There are some areas that we are looking at whether or not it makes sense for us to invest some in the water side, really to juice our E&P returns overall. These are good projects that will boost our E&P productivity and return. So incrementally, it is not a lot of capital overall, but it is very productive capital for us to spend.

Nicholas Pope: Got it. And so, total disposal capacity across the basin—you did a nice job of highlighting the movement of oil and where things are across the basin—but for capacity for water, are you all comfortable with the total capacity in the near term? They have been able to handle all the water that this basin is going to produce?

Michael H. Lou: 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. Overall, that is baked into all of our economics and our thoughts. There is a need to try to get water disposal a bit closer to your wellbores overall, and so that is why there is some ongoing capital spend on the water side. I do not think it really changes things as we move forward.

Nicholas Pope: Hi. Good morning. Thank you. In your 2025 reserves, I was wondering, did the full impact of your lateral length extensions get captured in your reserves?

Darrin J. Henke: As you are probably noting, the three-mile wells that we have delivered, we have captured that in our reserves. But as you probably know, we had actually just recently TILed the four-mile wells. So that is probably on the early side. Obviously, there might be one or two wells on that front, but it is not really fully captured when we think about the full PUD development. But it is pretty straightforward from the standpoint that what we saw in the three-mile results resulted in the type of uplift that we talked about.

Nicholas Pope: Great. Thanks. 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 at least for me, so much of the focus on the longer laterals, I know, raises the tier of maybe outer parts of the footprint to make locations viable that would not have been with shorter laterals. Are there implications for infill drilling in the more mature parts of the footprint, especially given the cost structure improvement that four-milers can introduce into the mix?

Danny Brown: No. It is a great question, and I think the answer is yes. There probably are beneficial implications as we get better at drilling these longer laterals. I think also, we do not talk about it very much because it is not a meaningful part of our program—it is 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 are fortunate that we have got such a great and extensive acreage position that we do not 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 shaped wells, I do think, has some implications to infill drilling. The important thing is we think as these costs get down, we are effectively draining the reservoir.

We have got good reservoir contact area. We think we are effectively draining the reservoir with what we have got now. But where these longer laterals and, maybe more importantly, the alternative shape wells can come with the infill drilling, it may allow us to go back in and capture some reserves that have not been really effectively drained. If you do not have the ability to drill these alternative shaped wells, you may not be able to access that very well. The combination of longer laterals and alternatives, I think, has a beneficial implication to infill development programs. We really have not quantified that yet, so I would say that is going to be a lot of upside to what we think about now. As our cost structure on these gets lower, as our ability to execute them gets larger, it probably just 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.

Operator: There are no further questions at this time. I would now like to turn the call back over to CEO, Danny Brown, for final closing comments.

Danny Brown: Thanks, Josh. To close out, I want to thank all of our employees for their continued hard work and dedication. We feel great about our competitive position and have a lot of low-decline, high oil cut production base paired with a deep inventory of highly economic, conservatively spaced oil-weighted locations. Our strategic actions and continuous improvement have created what we believe is a valuable and increasingly rare asset in our ability to deliver going forward. 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 line.