Operator: Good morning, ladies and gentlemen, and welcome to the Chord Energy First Quarter 2025 Earnings Call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on Wednesday, May 7, 2025. I would now like to turn the conference over to Bob Bakanauskas. Please go ahead.

Bob Bakanauskas: Appreciate it. Thank you. Good morning, everyone. This is Bob Bakanauskas. And today, we are reporting first 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 and 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 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.

Danny Brown : Thanks Bob. Good morning, everyone and thanks for joining our call. Over the next few minutes, I’ll plan to provide a brief overview of our first quarter performance and results in current capital, discuss the current macro environment and Chord’s position and then briefly touch upon some of our current initiatives before passing it over to Darrin, who will provide more color on our operations. Darrin will hand it over to Richard for more details on our financial results before we open up for Q&A. So turning to first quarter results. Chord delivered another great quarter with solid operating results yielding free cash flow above expectations which supported robust shareholder returns. Specifically, first quarter oil volumes were above the capital guidance reflecting strong execution in well performance while capital was favorable to guidance largely reflecting improved program efficiency.

Operating expenses also came in lower than our expectations as the team continues to drive improvements to our cost structure. And thanks to our entire organization for delivering favorable results once again and in particular to our folks in North Dakota who did an amazing job navigating extreme winter weather positioning us to surpass expectations. Fantastic job by all. This strong performance led to adjusted free cash flow for the first quarter of approximately $291 million. We maintain shareholder returns at 100% of free cashflow for the second consecutive quarter, repurchasing $216.5 million or about 2 million shares during the quarter. And since April 1, we have already repurchased another $45 million or about 500,000 shares at approximately $91 per share.

We will be paying our base dividend of $1.30 per share on the lower share account, which equates to approximately $75 million. Since closing the Enerplus transaction, Chord has reduced its share count by approximately 9% through the end of April. To put that in perspective, Cord has repurchased over a quarter of the shares issued to purchase Enerplus in less than a year since the transaction closed. And we were able to do this while keeping leverage essentially unchanged at about 0.3 times. Given our view on the intrinsic value of our shares relative to how they currently trade in the market, we expect a continued focus on share repurchases in the current environment. Turning to the macro, we are all keenly aware that the pricing outlook has deteriorated and volatility has increased since we entered the year and Chord is in the enviable position to navigate this type of environment.

In the event conditions remain unfavorable or weakened, Chord has substantial operational and financial flexibility to moderate activity and maintain an efficient returns focused program with strong free cash generation. As Slide 7 illustrates, Chord has one of the lowest base decline rates amongst its peers, which supports our low reinvestment rate. Additionally, on the land side, Chord has no material drilling obligations as our acreage is essentially all held by production. On the midstream side, Cord is well covered with very limited volume commitments and we have intentionally laddered and structured our service contracts to provide program optionality. And finally, at a leverage ratio of 0.3 times, our balance sheet strength stands out versus our peer group.

Our development plan also provides us with significant optionality. Chord started the year running five drilling rigs and two frac crews. In accordance with our original plan laid out in February, we have already reduced our frac crew count and by early June, we’ll be running a program consisting of four rigs and one frac crew. Both our original and current guidance reflect the return of the second frac crew in the fourth quarter of this year. This allows us to monitor the macro environment at a lower activity pace and gives us the option to either bring back this second frat crew or just keep one frat spread through the end of ‘25 and into 2026. Letting it be clear that at current strip prices, we are inclined to maintain one frac crew instead of reinstating the second frac crew near year end.

However, given the original plan already included a mid-year reduction in activity, we have several months to decide on this second frac spread with the final decision to be made in the third quarter. If Chord makes the decision to stay with one frac crew and not bring back the second, the production impact of 2025 would be negligible. However, fourth quarter capital would be much lower than current expectations. And I should note that last night Chord announced a $30 million reduction to its full year capital guidance. This $30 million reduction largely reflects program efficiencies and does not currently contemplate any reductions to activity given we have until the third quarter to make the final call. And once again, Chord’s full year volume expectations remain unchanged.

Next, I’d like to discuss some of our initiatives to increase free cash flow given our track record of innovation and continuous improvement. Slide 12 outlines approximately $3 billion of controllable cash, controllable costs across the business between operated D&C capital, lease operating expenses, marketing expenses, and G&A. There is a concerted effort across every part of the organization to improve our cost structure and drive efficiency. We’ve already made progress this year in reducing our capital investment in LOE guidance with no impact to volumes. Our culture is built around continuous improvement and advancing efficiencies to improve our capital productivity and margins. A good example of this is our recent decision to lean into four mile laterals with seven spuds now planned versus our original expectations of two to three.

This follows our first four mile lateral, which was successful on a variety of fronts, including being $1 million below budget and successfully cleaning the well out all the way to the toe. Production over the first couple of months for the well has been encouraging, but we really need to get past the flat period and initial decline to get a better sense of the ultimate productivity and recovery. Darrin will provide more details in his section, but it’s fair to say, we like what we’re seeing. In light of the improved capital efficiency and lower breakeven costs that long lateral development provides, Slide 11 illustrates an example of how Chord is reconfiguring acreage to optimize longer lateral development. You can see as Chord moves from the two mile scenario to the four mile scenario, it results in a 24% reduction in capital to develop the same amount of resource.

This results in stronger rates of return and lower break-even pricing. Our goal is to convert our inventory to over 80% long laterals in the coming years, which will enhance economic returns. Since I arrived at the company over four years ago, we’ve had a successful track record of keeping our sub-$60 inventory position strong. We’ve done this not just through disciplined M&A, but also organically, through wider spacing, longer laterals, and program efficiencies. Going forward, we expect to further improve our inventory strength and returns by extending laterals and driving down costs. This will include straight three and four miles, as well as alternate-shaped well designs. On the LOE side, we’ve leveraged our scale to get more efficient, systematize processes, and reduce downtime.

Looking forward, we have multiple initiatives to drive further improvement, including artificial lift optimization, faster cycle times, logistics improvements, and potentially leveraging newer technologies, such as predictive maintenance and remote well site monitoring. On the marketing side, we’re driving efficiency through consolidating contracts from predecessor companies and negotiating competitive rates when contracts mature. Also, on the gas and NGL side, we are adding more dual and split connections to our facilities, which provides midstream optionality when the gas plants are down. This has the dual benefit of higher gas capture rates and additional revenue. Lastly, a few words on sustainability before handing it to Darrin. I want to reemphasize that Chord is proud of our work providing reliable and affordable sources of energy, so critical to every aspect of modern living.

And we do this while maintaining a commitment to operating in a sustainable and responsible manner. On this front, Chord continues to make progress on our already strong sustainability initiatives with a focus on putting safety first, minimizing our environmental impact, and being a good partner in our communities. We plan to publish an updated Sustainability Report in the second half of this year, which will reflect the full integration of Chord and Enerplus. So, to summarize, while markets have taken a turn for the worse in recent months, Chord has a strong foundation and significant flexibility to adjust if needed. Chord was built around modest mid-cycle oil price expectations with the recognition that we operate in a cyclical business and there will inevitably be downturns from time to time.

The steps we’ve taken over the past four years have lowered our cost structure, strengthened our inventory position, and enhanced flexibility in our development program, all while keeping the balance sheet and liquidity in an enviable place, allowing us to better navigate times like these. And with that, I’ll turn it to Darrin.

Darrin Henke: Thanks, Danny. While the macro environment is challenging, the Chord team continues to execute with excellence, and we’re off to a great start this year. We have tremendous confidence in our execution ability, and we have the flexibility and optionality to reduce activity if needed while still generating significant free cash flow at lower prices. As Danny mentioned, we are laser-focused on driving continued efficiency throughout the program. As a result, we were able to lower our 2025 capital by $30 million without changing our production targets. This $30 million reduction is incremental to the $90 million reduction to the 2025 budget versus pro forma 2024 capital. Furthermore, this $30 million reduction is also net of expected tariff pressure later in the year, which wasn’t contemplated in our February guidance.

We’ve certainly made a lot of progress improving capital productivity over the past year. Since we’re on the topic of efficiency improvements, we wanted to give you an update on Chord four-mile program. As announced earlier in the year, Chord successfully drilled and completed our first four-mile lateral and reached a TD exceeding 30,400 feet while cleaning out the frac plugs. The clean-out was executed in only one run and was much faster than we originally expected, leading to a total well cost approximately $1 million below the original budget. Additionally, we ran tracers on this well and subsequently observed every stage of the lateral contributing to production. Initial volumes and pressure indications are encouraging, but we need to monitor the flat period and initial decline before drawing definitive conclusions.

Over the spring, Chord successfully drilled two additional four-mile wells, with drilling times, again, faster than expected. These wells are in the queue to be completed later this year. As we announced in April, we’re planning to spud a total of seven four-mile wells over the next eight to nine months, and with success, Chord is likely to implement many more in 2026 and beyond. As a reminder, our initial approach to four-mile wells will be converting two two-mile DSUs to one four-mile DSU. However, similar to Chord’s evolution on the three-mile program, as we make progress on execution and drive the risk-adjusted returns higher, we could ultimately look to convert some of our existing three-mile inventory into four-mile wells. Relative to two-mile wells, four-mile wells are expected to recover 90% to 100% more ultimate recovery for only 40% to 60% more capital.

On a breakeven basis, four-mile laterals are expected to be anywhere from $8 to $12 per barrel lower than two-mile wells. It’s important to remember that all else equal, longer laterals will deliver slightly higher IPs versus two-mile wells, staying flatter longer and exhibit shallower declines. When comparing analog well performance on a per-foot of lateral basis, initially longer lateral wells will typically be lower than two-mile wells, as the higher IP is more than offset by the longer lateral. However, typically in a 6 to 12-month period, the longer flat period and shallower declines will lead longer laterals to catch up to the two-mile well on a recovery per-foot basis. Additionally, Chord’s choke methodology is more restrictive than most peers, which minimizes sand flowback and ultimately lengthens the life of our ESPs, saving costs and delivering higher returns on average.

Given our focus on improved returns versus higher IP rates, we have been implementing this more restrictive choke program on the Enerplus wells, which will impact the optics of initial IP rates per foot on a year-over-year basis. Again, per-foot performance is an appropriate way to judge well productivity over the long term, but early data can and often is misleading. Turning to LOE, Chord lowered its full-year guidance reflecting strong first-quarter execution and our current outlook. LOE has been a major focal point for the company in recent years, and Chord has been able to drive efficiency improvements through multiple avenues, including streamlining workover expenses and reducing downtime. Chord strives for additional improvements as we competently manage capital allocation, maximize returns, and efficiently generate free cash flow.

Lastly, I wanted to comment on Chord’s operational efficiency. Our teams continue to perform with excellence and aim to drive cycle times lower for both drilling and completions. We are drilling three-mile wells 13% faster than a year ago, and our full-time frac crew is using sample frac operations on most pads, which has driven down non-productive time and materially increased the lateral footage completed on a daily basis. Pumping hours per month are also well above basin peers. On the post-frac cleanout side, Chord continues to drive faster cycle times as we leave the basin in three-mile laterals. To sum it up, Cord’s execution and delivery remain best in class. We’re off to a great start in 2025 and look forward to additional progress as our teams relentlessly pursue continuous improvement and innovative solutions.

I’ll now turn it over to Richard.

Richard Robuck : Thanks, Darrin. I’ll round out our conversation with some final thoughts that expand on comments made earlier and in our press release. I’ll start with the strength of our balance sheet. In the first quarter, the team completed the issuance of a $750 million senior secured notes at 6.75% that are due in 2033, and by increasing our elected commitment amounts under our revolver to $2 billion. We continue to have pure leading leverage and strong liquidity as we navigate the current environment. We also layered on additional hedges during the first quarter, and our derivative position can be found in our latest investor deck. Next, I’ll cover differentials. Oil differentials in the first quarter averaged $2.30 below WTI, which weakened slightly from our prior quarter but were within our original guidance range.

We expect oil differentials to improve modestly over the course of the year, which is reflected in our updated guidance. NGL realizations were 20% of WTI in the first quarter, just above the midpoint guidance. Natural gas realizations of 63% were above the top end of guidance and benefited from seasonally strong regional prices in both the Bakken and Marcellus. We anticipate realized natural gas prices to soften during the middle of the year before improving modestly toward the end of the year, reflecting normal seasonality. As a reminder, certain marketing fixed fees are deducted from our NGL and natural gas prices. This drives higher operating leverage, which hurts realizations for both NGLs and natural gas in times of weaker prices and benefits realizations in times of higher prices.

Separately, the team has done a great job managing costs, beating first quarter guidance with continued momentum for the balance of the year as LOE is down $0.30 per BOE and capital is down $30 million in our 2025 guidance. Production taxes averaged 6.8% of commodity sales in the first quarter, which was below our expectations. This primarily reflects the impact of non-recurring refund for stripper wells that received an adjusted tax rate during the quarter. The oil revenue from these low producing wells is taxed at a reduced rate. Additionally, the production tax rate was impacted by higher gas revenues as a percent of total sales as gas is taxed differently than oil. For the remainder of the year, we anticipate production taxes to average 8.5% of commodity sales.

First quarter cash taxes were in line with our expectations at $34 million and we expect full year cash taxes to approximate 4% to 9% at WTI prices ranging between $55 and $75 per barrel. There have been no changes to full year cash tax guidance issued in February other than the yearly range now reflects actual first quarter results. In closing, thanks again to the Chord team for all their hard work and intense focus on improving day-to-day operations during the period of market uncertainty. We are pleased with the company’s first quarter performance and believe that we are in a strong position to successfully deliver on our goals for the remainder of the year. With that, I’ll hand the call over to Vincent for questions.

Operator: Ladies and gentlemen, we will now begin question-and-answer session. [Operator Instructions] First question comes from Oliver Huang with TPH. Please go ahead.

Oliver Huang: Good morning, Danny and team, and thanks for taking the questions. Just wanted to start on activity levels. And I know there are many variables that go into the decision-making process and understand the biases to not pick up the spot right crew in Q4 at this time, whether it is more returns driven or just not wanting to chew through precious inventory at these oil prices. But if we’re talking about crude with a five handle on it once Q4 and even early 2026 comes around, would one full-time simulfrac fleet be the default optimal ballpark of activity levels for 2026 as well? If you could just maybe walk through the thought process on what would need to happen to justify the bringing back of the spot crude for a portion of the year.

Danny Brown: Thanks for the question, Oliver. And I think you framed it well. At the end of the day, it’s really just a capital allocation decision for us. And it’s going to depend on a variety of factors. So we’ll be looking at service costs based on this. We’ll be looking at our own share price candidly because, again, it’s just a capital allocation decision. But all else being equal, I think what we would want to see is oil, I would say, firmly and what we would think would be in the 60s in order to bring that second frac crew back. So with oil at a five handle, again, all else equal, we probably would anticipate we’d have better capital allocation opportunities in an environment like that. And that’s kind of how we’re thinking about it.

But again, we have not made that decision. We are in a really nice place just naturally through our program that we’ve reduced activity in this environment. And it gives us a chance to monitor. And so we’ve gone down to the single frac crew that’s doing simulfracs for us. It’s a very efficient program. And we’ll maintain this. And we’ll really make a final call on this in the third quarter. So no decisions have been made, but wanted to be transparent about kind of how we’re thinking about this environment, and I think you framed the situation well.

Oliver Huang: Thanks, Danny. That’s helpful color. And maybe for a follow-up, I think Slide 11 does a really good job in illustrating the magnitude of potential capital savings with a four-mile lateral program. And I know Darrin hit on it very briefly in the prepared remarks, but should we think about the potential move to incorporate a four-mile development plan being more gradual or an immediate jump from that 40% to 50% to the 80% goal? Because it would seem that once you’re able to confirm the success, there should be very minimal reason to do two-mile laterals within the program. And any sort of color in terms of time frame we could see this progression on? And if you could remind us how big of an undertaking this would be in terms of altering previously approved permits?

Danny Brown: Yeah, I think you, again, you framed it pretty well. As we look at this, we moved over from a two-mile to a three-mile program pretty quickly. And I would say we’re probably poised to move to a four-mile program about equally as quickly, maybe slightly more quickly, candidly, because we sort of built up some courage and some operational ability as we progress through the three-mile program, gotten better at cleaning out our wells, have — are starting to get four miles under our belt now. And so I suspect that we could move over to that program pretty swiftly and maybe even a little more swiftly than we’ve moved over to a three-mile program. It will require us repermitting. It’s going to require some work from the development team to sort of optimally lay out all of these different pads.

And because it’s — if you think about it, we have sticks laid out on a map for every single sort of spot and inventory location that we’ve got. And so it’s really a full recontemplation of our development plan, which includes roads, midstream connections, everything that’s associated with that as you work through this. So that does take a little time for us to work through. We’ve got to go through the permit process. But I would suspect we’ll be able to move to this more swiftly than we did a three-mile program. Yeah, and so I’ll kind of leave it there. But we’re encouraged with what we’re seeing. We think it’s a great opportunity, and I think we could move over to a program in a reasonably swift manner.

Oliver Huang: Awesome, thanks for the time Danny.

Danny Brown: Thank you.

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

Noah Hungness : Good morning, everyone. For my first question here, first quarter looks like a really strong quarter with oil production higher than expected. 2Q also looks stronger than a lot of us had in our models. Could you maybe talk to us about how the oil cadence — what the oil cadence looks like for 3Q and 4Q for this year?

Danny Brown: Yeah. Thanks for the question, Noah. I think if you look at kind of how we’re guiding for the full year relative to what we just did for 1Q and 2Q, you can kind of imply that we’ll be — oil will be drifting down, particularly in the fourth quarter. And if you think about what we’ve talked about the fact that we’re dropping to a one crew program right now and contemplating picking one up again in the fourth quarter, that also ought to imply a little bit on the cadence of our oil production. And so we do anticipate oil production is going to fall as we move into the back end of the year. If we elect to pick up that second frac crew in the fourth quarter that will obviously will start completing those wells, we’ll TIL them maybe starting at the very end of the fourth quarter, but really into 2026, and you’ll see that production cadence pick back up again.

But yeah, we do anticipate seeing oil fall a little bit as we’ve dropped this frac crew. We’ll bring TILs on through the third quarter. We won’t bring as many TILs on in the fourth quarter. And so you’ll start to see our production volumes fall a little bit into 4Q. And if we pick that frac crew up, they’ll move back up again in 1Q.

Noah Hungness : And for the third quarter, last quarter results, you mentioned that 3Q would be above 2Q. Should we kind of think maybe put 2Q rising that 3Q would be flat versus the prior quarter?

Danny Brown: Yeah. I think flattish to 2Q is probably a good expectation.

Noah Hungness : Great. And then for my second question, just could you maybe add a little more color on what’s giving you guys the confidence to increase your original plan from spudding three, four-mile laterals to seven? And then will you be testing anything new with these additional wells like a different cleanout technique or anything else?

Danny Brown: Yeah. I think we’ve just seen — we’ve seen positive results is the short answer, but I’m going to turn it over to Darrin to provide a little more color. But we like what we’re seeing so far, and that’s giving us a little confidence, but I’ll turn it to Darrin for more color.

Darrin Henke : Yeah. So we have three wells drilled now, and each well is drilled better than we anticipated. We’ve seen lower torque and drag. Just really operationally, everything has gone as well or better than expected. So that’s definitely given us confidence to move forward with additional testing additional wells, which will help us convert to, ideally, a more longer lateral program, four miles, et cetera. Down the road, four miles, and when I say et cetera, I’m talking about alternate well shape as well. So really, everything is going very well operationally in that regard, Noah. So that’s just given us confidence to press forward faster.

Noah Hungness : Make sense, guys. Thanks.

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

Derrick Whitfield : Good morning all, congrats on a strong 1Q.

Danny Brown: Thanks, Derrick.

Derrick Whitfield : Wanted to focus on your maintenance capital as my first question. If we were to assume the approximate 150,000 barrel per day rate implied by your second half guide, could the current rate of activity generate flattish growth in 2026? And if so, what would the maintenance capital be to sustain that at current cost and optimal level through all or greater laterals?

Danny Brown: Yeah. I think if the question — for us to maintain — 152.5 is around 1.5 crew program. And so if we go down to something sub that, I think we would — that’s probably unlikely to maintain a 150 program. And so it would be something sub that if you’re talking about a one crew simulfrac program.

Derrick Whitfield : Terrific. And then just any color on what that would be from a capital perspective as you guys see cost at current?

Danny Brown: Yeah. So as we’re looking into ’26, I will say that as we think about, one, I wouldn’t normally give — we don’t really start giving soft guidance until the third quarter for the prompt year. And so we’re clearly ahead of that. And lots in a very, very dynamic environment. But generally speaking, if we’re looking into — if we pull — go down to a one frac crew program, you’re probably talking about around a third of our operated activity coming out of the program through ’26. And so that’s sort of the impact associated with this. And so that that 1.5 crews, you just think about it delivering about a third of the TILs over the course of the year. So that’s the impact capital would be associated with that. And clearly, some wedge volume would be associated with that as well if we follow that path.

Derrick Whitfield : Great. And then maybe just shifting over to your self-help slide on Page 12. Danny, if you or Darrin could just speak to how material the LOE and market contract opportunities could be to lower your cash costs? I know several of your marketing contracts are set to renew over the next couple of years.

Danny Brown: I think we’ve got a tremendous opportunity in this space. And clearly, we’re focused on CapEx, and CapEx gets a lot of the headline numbers. But these other pieces have just as big an impact on free cash flow. Any dollar, say, regardless of the bucket it comes from just translates right into that — right into that incremental free cash flow column. To your point, we do have marketing contracts that are rolling off over the next few years. That gives us opportunities to renegotiate there. We’ve also seen tremendous benefit. I mentioned in my prepared comments, we’ve consolidated some contracts. If you think about it, we’ve got three legacy organizations, all of which had contracts with different midstream providers.

Some of those, it was a little unwieldy for both parties to manage those contracts. And so we’ve been able to consolidate into a single contract that offered us better rates. So that’s a good thing. And then from an LOE perspective, I just think we’ve got tremendous opportunity there as we continue to leverage the scale we’ve built as an organization to improve and lower LOE. But maybe I’ll give Darrin opportunity to talk a little bit about some of the specifics we’re looking at.

Darrin Henke : Yeah, we continue to work with our vendors to reduce our costs, particularly chemical costs, things of that nature. Also spending a tremendous amount of time getting the Enerplus wells — the legacy Enerplus wells to have the same run times that we have on the legacy Chord wells. And so if we can reduce the downtime, improve run times, spread out the — requiring fewer workovers into the future, that obviously saves us a lot of money and improves cash flow with the additional production. So just never ending, looking at these type of opportunities, Derrick.

Derrick Whitfield : Thanks. That’s great. I’ll turn it back to the operator.

Operator: The next question comes from Paul Diamond with Citi. Please go ahead.

Paul Diamond : Good morning. Thanks for taking the question. Just a quick one. Could you talk — give a bit more detail on kind of the total addressable market, those four-mile laterals versus locations? Talk about being 50% of the program, but should we think about that extrapolating out kind of the wider inventory numbers? Or is there a different kind of decline rate in that over time?

Danny Brown: Thanks for the question, Paul. So as we think about our — I’m going to frame this around long lateral inventory. And so long lateral inventory. We’re trying to shoot to sort of over 80% of our total inventory set. Four-mile laterals, as you think about the opportunity set there, that’s probably under 50% of the program, but 80% is what we’re shooting for, for three miles, let’s call it, three-mile plus, which just offers tremendous incremental efficiency gains relative to what we would see from a two-mile program. And what was the second part of your question?

Paul Diamond : No. Just should we — can we extrapolate that over time to like total sticks like on the inventory perspective? Should we expect that to maintain over time?

Danny Brown: Yeah. So as we — the nice thing about doing this is it just really does lower our breakeven economics here pretty significantly. And so as we do that, obviously, inventory that might not have been compelling for us to go develop previously becomes — starts to offer really attractive rates of return. And so you do sort of suck some inventory into the system when you’re able to lower your breakeven cost, which we’re able to do with these four-mile laterals. And so I do think it does have a dual benefit not only of improving our capital efficiency, but also sort of giving us more runway to go continue to develop the field.

Paul Diamond : Understood. Makes perfect sense. And just a quick follow-up. Given the current volatility, how should we think about any shifting sentiment with the macro? And as far as how that would kind of read through into your willingness to either expand or contract your existing hedge book?

Danny Brown: Yeah. Lots of volatility clearly within the marketplace right now. We try to take — we take a reasonably conservative view on hedging part of the — part of our opportunity here is we have a fantastic balance sheet. We have low reinvestment rate. We’ve got strong free cash generation, even down to very low prices. And what we found is, over time, human nature seems to be that you hedge at the exact wrong times. When oil is high, you think it’s going to go higher and you won’t hedge. And when oil is low, you think it’s going to stay low forever, so you hedge and you’ve done just the exact wrong thing. So I think one of the great things is that just the resiliency of the business and the organization we’ve created is a great hedge to us.

Having said that, we think some predictability is helpful. So you’ve sort of seen our hedge book get created. We don’t want to be more than about 40% hedged in the past quarter. We typically hedge less and lower prices, hedge more and higher prices. And that’s kind of how we look at hedging. And so I don’t really see a change to that framework because our whole framework on how we think about hedging is in recognition of the fact that we’re in a cyclical business. And so not much change to our philosophy there.

Paul Diamond : Understood. Appreciate the clarity. I’ll leave it there.

Danny Brown: Thanks, Paul

Operator: The next question comes from Josh Silverstein with UBS. Please go ahead.

Josh Silverstein : Yeah, thanks. Good morning, guys. Just wanted to ask on a couple of questions on the M&A side. First, just on the Marcellus, just wanted to see how you’re thinking about that asset. Obviously, stronger gas prices this year relative to last year. How are you thinking about that as kind of a Chord fit within the portfolio right now and potentially use the proceeds there?

Danny Brown: Yeah. So as we’ve said before, we like that asset. It’s in the core of the basin. We’ve got a great operating partner associated with that. However, it’s not core for our organization. And so we recognize that that’s not a noncore position for us, and we’re going to look to maximize value on that over time. Clearly, gas price relative to oil price is more constructive now than it has been historically. And so we’re always looking at how we can maximize value.

Josh Silverstein : And then just on Williston M&A, you guys are always active and looking to do some bolt-ons and other transactions. Have you seen any change in valuations or how people are thinking about transacting in the basin just given the lower oil prices right now?

Danny Brown: I’d say it’s the move has been pretty swift and still fairly recent. As a general comment, I would say that significant and rapid movements in price aren’t really helpful for M&A, just in that it creates a bid ask spread between buyers and sellers. That’s not really helpful to getting deals done. So price stability is always a nice thing to have if you want to get deals done. So I haven’t really seen any significant impact. But by the same token, I think it’s our expectation that M&A may just be a little bit more challenged in this environment than it would be in an environment of more stability.

Josh Silverstein : Thanks, guys.

Danny Brown: Thanks, Josh.

Operator: Next question comes from Geoff Jay with Daniel Energy Partners. Please go ahead.

Geoff Jay: Hi, guys. The question is really about sort of the increase in cycle times from sort of two-mile to three-mile to four-mile. And as you sort of migrate to a greater percentage of the longer laterals. How will that sort of change your, I guess, cadence of spending and production if you kind of look out to 2026 and 2027?

Danny Brown: Yeah. My expectation is that as we’ve — the cycle time per well increases, but the cycle time per foot decreases. And so as you think about that, you can accomplish the same sort of lateral foot drilling with lower capital cost and fewer wells. And so it all depends on what you’re solving for. If you’re solving for delivering a particular well count, that’s one issue, but we’re solving — that’s not necessarily what we’re solving for. And so I think what we’re going to look at is — how does the — again, what’s the right capital allocation decision for us in the environment that we’re in. And then the production will be an output of that, not necessarily an input to that. So the nice thing is that, again, the cycle times stretch out a little bit, but the delivery — the per foot delivery actually improves pretty significantly associated with this.

Geoff Jay: That’s fair. And then just a follow-up on Paul’s question from earlier, just to make sure I understand the answer. When I look at Slide 6 with your inventory life at both sort of sub-50 and sub-60. As you migrate to the longer laterals, you’re saying there won’t be significant degradation in sort of the inventory life of the program?

Danny Brown: Yeah, because we’re measuring inventory life, not necessarily a stick count but on a sort of what we’re — relative to production capacity and reserve delivery relative to what we’re currently producing.

Geoff Jay: Thank you, guys.

Danny Brown: Thanks, Geoff.

Operator: Next question comes from Noel Parks with Tuohy Brothers Investment Research. Please go ahead.

Noel Parks : Hi, good morning. I apologize if you touched on this already, but can you talk about sort of the potential footprint expansion that four-miles could give you, just making locations or parts of the play that were not quite economic feasible?

Danny Brown: Yeah. I don’t know how much specific I can provide around that. We’ve got some acreage maps that we’ve put out in the past, and we’re probably happy to visit on this sort of off-line on areas where — it was more at the very outskirts of the basin, areas where it was a little tougher for us to compete with capital. And so as we go for those opportunities to compete for capital — as we move into four miles, I think some of those start to fall in to where they do offer very attractive rates of returns associated with development out there. And so there is — there will be a small footprint expansion associated with going successfully moving to four-mile laterals, again, just because of the breakeven cost. Just because of the breakeven cost improvement that we’ll see due to the more efficient development design.

Michael Lou : No, the only thing I’ll add to that — this is Michael. The only thing I’ll add to that is the team has done an incredible job over the last few years, increasing capital efficiency through three-mile laterals, spacing, four-mile laterals, all these things are continuing to help the program. You heard in Danny’s prepared remarks, he talked about a 10-year inventory life that’s sub-60, and we’ve been able to hold that flat at 10 years for the last 4 years. Some of that’s through M&A, but a lot of that is through this continuous improvement. And the team really improving economics and bringing, like you’re saying, acreage that currently isn’t sub-60 into that sub-60 category. We still have quite a bit of the acreage that’s not in that sub-60 category today that four-mile laterals and continued kind of improvements from the team will continue to bring that into that 10-year inventory life and push down our current inventory life to a lower breakeven.

So the team is doing a great job on that front.

Noel Parks : Great. Great. And again, this is something that would just be incremental. But as I look ahead to the implications of the longer laterals sort of rippling through. Would you have enough data, production data from your first or early four-milers to be able to get any bits of re-rating upward as far as reserve bookings? I don’t know if he had two two-mile pubs on the books that we’re going to go to four with the better economics and so forth. And would that needle get moved at all?

Danny Brown: I think for our proven reserve base right now, as we move 2 2s to a 4, we’re really just capturing that entire resource that’s kind of already accounted for, just in a more cost-effective manner. As we’re able to expand our opportunity to capture out because we have better breakeven economics, what will happen is we’ll have sort of more inventory associated with that. That will move their way into the proven undeveloped category over time. And so I think the actual wells themselves probably were just capturing what we hope will be 100% of the resource of those two-mile wells. We still need to see that over time. We’re seeing that on 3s. We still need to make sure that that’s the case on 4s. But as we expand — as we lower breakevens and expand our ability to expand the basin, we’ll bring more wells in which will make their way — will migrate their way into proven and underdeveloped. And so — and have a positive reserve impact for us.

Darrin Henke : So over time, there’s a reserve impact biased upward and then capital bias downward, so the PV should be biased upward.

Noel Parks : Terrific. Thanks a lot

Darrin Henke : Thanks, Noel.

Operator: There are no further questions. I’ll now turn the call back over to Danny.

Danny Brown: Thanks, Vincent. Well, to close out, I want to thank all of our employees for their continued hard work and dedication to our organization. Despite the macroeconomic headwinds, this is the best position the company has been since I arrived four years ago. Our strategic actions, coupled with our fantastic operations team, have created what we believe is a valuable and increasingly rare asset. Chord has substantial yet low decline and high cut — high oil cut production base, which is paired with a deep portfolio of highly economic lower-risk, conservatively spaced and oil-rich inventory. We feel great about what we’ve accomplished and have a lot of confidence in our ability to deliver going forward. As you can imagine, we will be closely monitoring the oil price environment and have the organizational flexibility to optimize capital allocation to drive returns and continue to generate strong free cash flow.

And with that, I appreciate everyone’s interest, and thank you for joining our call.

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

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CHORD ENERGY CORP

Q1 2025

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