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Operator: Good morning, ladies and gentlemen. And welcome to the Chord Energy Corporation Fourth Quarter 2024 Earnings Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question and answer session. If at any time during this call, you require immediate assistance, this call is being recorded on Wednesday, February 26, 2025. I would now like to turn the conference over to Bob Bakanauskas. Please go ahead.

Bob Bakanauskas: Thanks, Andrew. Good morning, everyone. This is Bob Bakanauskas, and today we are reporting fourth quarter 2024 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 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 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. Morning, everyone, and thanks for joining our call. Over the next few minutes, I plan to reflect on Chord’s 2024 accomplishments, provide a brief overview on fourth quarter performance and resulting return of capital, and then turn the discussion to our 2025 outlook. From there, I’ll turn it to Darrin who will comment on Chord’s operations. Darrin will then pass it to Richard for more details on our financial results before we open it up for Q&A. So starting with 2024, last year was a transformational year for our organization. We solidified our leading position in the Williston Basin by entering into a combination with another leader in the basin, Enerplus. The combination closed in May of last year, and we successfully extracted significant value from the integration by focusing on incorporating best practices from both organizations.

This allowed us to capture substantial operational and corporate synergies. Notably, we executed this transaction while maintaining our commitment to balance sheet strength, capital discipline, and peer-leading return of capital. To that point, I believe this is the best position the company has been in since I arrived four years ago. We have become a basin leader, and our improved scale has driven a highly efficient program capable of generating flat to slight volume growth with low maintenance capital, resulting in high amounts of sustainable free cash flow. We have enhanced our economics by adopting leading-edge practices such as long laterals and conservative spacing, which have lowered our breakevens and extended inventory life. As we look to the future, Chord’s substantial low-cost inventory generates attractive economics and allows for continued low reinvestment rates, robust free cash flow, and attractive return of capital.

In short, we have demonstrated consistent delivery for shareholders and have additional catalysts for future upside. Our capital-efficient development and solid operational performance resulted in strong free cash generation last year, and a significant portion of this was returned to shareholders. In 2024, on a pro forma basis, Chord returned $944 million to shareholders. In recent quarters, you’ve likely noted that we’ve leaned harder into share repurchases to take advantage of what we view as a value disconnect in our share price. Since closing the Enerplus transaction, Chord has repurchased greater than 5% of its shares outstanding, and we expect a continued focus on share repurchases in the current environment, which should yield per share growth across all key metrics.

One example of this can be seen on slide six of our presentation, where we show that Chord has grown oil production per share at a 12% compounded annual growth rate over the last three years. Importantly, we did this while simultaneously preserving our balance sheet and paying out approximately $2 billion in dividends. Given our strong inventory and lower investment rate, and what we see as a compelling valuation on both an absolute and relative basis, which we highlight on slide four, we see no reason why strong per share growth won’t continue. Turning to fourth quarter results, Chord delivered another great quarter with solid operating results yielding free cash flow above expectations, which supported robust shareholder returns. Specifically, fourth quarter oil volumes were above the midpoint of guidance, reflecting strong capital was below expectations, largely reflecting fluctuations in program timing.

Operating expenses also came in below expectations as the team continues to focus on improving cash margins. Thanks to our field, development, and execution teams for delivering favorable results across the board in the fourth quarter, and really all of 2024. Fantastic job by all. This strong performance led to adjusted free cash flow for the fourth quarter of approximately $282 million, and Chord stepped up shareholder returns to 100% of free cash flow to take advantage of the discount we see in our shares. Share repurchases comprised all of our return of capital for the quarter after accounting for the base dividend, which was increased by 4% to $1.30 per share. Turning our attention to 2025, as you’ll recall, this past November, Chord released its first multi-year outlook, and our 2025 guidance released last night demonstrates we’re off to a strong start.

Despite some stretches of brutally cold weather, the asset is performing well, and our latest projections, including the impacts of this weather, are reflected in our first quarter guidance. As for the details surrounding our 2025 plan, this year we intend to run a maintenance capital program and are currently running five rigs, which we expect to decrease to four by midyear. Additionally, we are currently running one full-time frac crew and one spot crew. We expect to turn in line between 130 to 150 gross wells, including 22 to 32 in the first quarter. The remainder of 2025 wells are expected to be spread out across the year. Average working interest in 2025 is expected to be approximately 80%, and a little over 40% of the 2025 turn-in lines are expected to be three-mile laterals, which should increase to over 50% in 2026 and 2027.

In addition to the operated program, we expect to invest between $205 million and $225 million on non-operated opportunities, approximately 80% of that in the Williston, with the balance in Marcellus. The 2025 program is expected to deliver production similar to pro forma 2024, between 152,000 to 153,000 barrels of oil per day with $1.4 billion of capital investment. This is approximately $90 million less than last year on a same-same basis and does include around $10 million which slipped from the fourth quarter of last year into the first quarter of this year. At benchmark prices of $70 per barrel of oil and $3.50 per MMBtu of natural gas, we expect to generate approximately $860 million of free cash flow in 2025 with a reinvestment rate of around 60% for the year.

As we progress through the year, Chord will continue to have a laser focus on improving our already strong capital efficiency and delivering strong investment returns. On slide seven of our investor presentation, you can find a third-party research firm’s assessment of Chord’s capital efficiency versus peers in 2024 and 2025. You’ll see that we’re on the better end of capital productivity and one of the few companies improving efficiency year on year. This reflects improving productivity partially driven by our pivot towards longer laterals, which Darrin will discuss a bit more. Speaking of turning this over to Darrin, the last thing I wanted to cover before doing so is our commitment to sustainability. Chord is proud of our work providing reliable and affordable sources of energy so critical to every aspect of modern living.

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 initiative with a focus on putting safety first, minimizing our environmental impact, and being a good partner in our communities. So to summarize, Chord had a great 2024, we’re off to a strong start in 2025, and we believe we offer a unique value proposition to investors: a compelling opportunity to invest in quality assets with proven execution, strong investment returns, and substantial return of capital to shareholders. And with that, I’ll turn it over to Darrin.

Darrin Henke: Thanks, Danny. Operationally, Chord continues to hit our stride, and we’re off to a great start on our three-year plan issued in November. We view this three-year outlook as conservative as it assumes no further improvements in capital efficiency relative to our year-end 2024 capabilities. Thus, the outlook includes no incremental benefits from faster cycle times, additional three-mile laterals, or four-mile laterals, all of which are focal points for the organization. Currently, the three-year plan projects over 50% to be three-mile laterals, and Chord’s total inventory is over 60% three-mile laterals on a lateral adjusted foot basis. We believe we can increase this percentage materially over the next few years, improving the economics associated with both our three-year plan and our overall inventory.

Just a quick update on four-mile laterals: Chord successfully drilled and completed our first four-mile lateral, and we just reached a TD exceeding 30,400 feet while cleaning out the frac plugs. We’re planning several more four-mile laterals in 2025, and with success, 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 ultimately could look to convert some of our existing three-mile inventory into four-mile wells. Since we’re on the topic of longer laterals, I’d like to discuss some nuances of these longer wells given how unique they are to Chord’s story.

Slide nine highlights the economic benefits of three-mile laterals, which deliver 50% more EUR than two-mile wells for only 20% more capital. This relationship is consistent when comparing wells with analogous geology and well spacing. Over the past several years, Chord has drilled fewer two-mile wells in the core and shifted towards more three-mile wells on its western acreage. On the lower right-hand side of slide nine, you can see a contrast between a two-mile Chord well and a three-mile well on our western acreage. The F&D cost for the western three-mile well is actually better than the core two-mile well, as lower D&C cost per foot more than offset the lower EUR per foot. Set another way, longer laterals outside the core actually have similar or better returns than two-mile wells inside the core, as core wells generally have higher costs given the depth, pressure, and other complexities that need to be managed.

Well productivity and EUR are certainly key factors for generating attractive returns, but the cost side is equally important. The production profile of longer laterals also differs from shorter laterals. All else equal, a three-mile well will deliver a slightly higher IP, stay flat longer, and exhibit shallower declines than a two-mile well. When comparing analog well performance per foot of lateral, initially, three-mile wells will typically be lower than two-mile wells, as the higher IP is more than offset by the 50% longer lateral. However, over time, the longer flat period and shallower declines will lead the three-mile well to catch up to the two-mile well on an EUR per foot basis. As Danny alluded to last quarter, Chord’s choke methodology is more restrictive than most peers, which prevents sand flow back and ultimately lengthens the life of our ESPs, saving costs.

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, perfect performance is the appropriate way to judge well productivity over the long term, but early data is often misleading. On slide ten, you can see Chord’s 2023 and 2024 lateral length-adjusted average well productivity relative to drilling and completion costs. By dividing well productivity per foot by drilling and completion cost per foot, it gives a sense as to the overall capital efficiency. As you can see, the 2024 program is superior to 2023, and we expect the 2025, 2026, and 2027 programs at a minimum to deliver similar capital efficiency as 2024. Turning to inventory, slide five shows Chord’s inventory depth and breakeven pricing versus peers as assembled by an independent research firm, which strives to use similar modeling methods across each company represented.

The key takeaway is Chord’s inventory is very competitive with peers. While we evaluate our inventory differently than the third party, we believe their analysis is objective and consistent. Additionally, we overlaid valuation multiples into the analysis to illustrate Chord’s attractive valuation, particularly in light of our relative inventory depth and quality. Lastly, I wanted to comment on Chord’s operational efficiency. Our teams continue to execute with excellence and aim to drive cycle times lower for both drilling and completions. On the drilling side, we reduced cycle times on three-mile wells by about one and a half days in 2024 versus 2023 and regularly set new records on the Enerplus acreage. On the completion side, our full-time frac crews are using simul frac operations on most pads, which has driven down non-productive time.

Lateral feet completed per day has increased by about 40% as compared to zipper fracs, generating well cost savings and reaching first production quicker. Finally, downtime continues to be minimized as the Chord team successfully navigated very frigid weather in January and February, keeping outages brief and getting volumes back online quickly. To sum it up, Chord is driving continuous improvement and innovation on our asset base, and it’s really showing in our execution and delivery. I’ll now turn it over to Richard.

Richard Robuck: Thanks, Darrin. I’ll discuss fourth quarter performance in more detail and give some color on 2025 guidance as well. In the fourth quarter, Chord generated adjusted free cash flow of $282 million, which was above expectations due to strong volumes, better gas and NGL realizations, lower capital, and good cost control. Oil volumes were above midpoint guidance and above the top end, reflecting strong well performance. Oil realization in the fourth quarter averaged about $1.50 below WTI, which was flat to prior quarters. We expect oil differentials to widen some in the first quarter of 2025 following an increase in basin production growth in the fourth quarter, but it will improve gradually over the course of the year.

NGL realizations were 14% from WTI in the fourth quarter, near the top end of our guidance range, and natural gas realizations were stronger than expected at 43% of Henry Hub, realized gas prices in the Bakken due to improving differentials for the regional benchmarks such as Ventura and AECO, which narrowed the gap against Henry Hub in the fourth quarter. This typically happens when winter weather hits, and in fact, the benchmarks can exceed Henry Hub at times. This strength, driven largely by cold weather, persisted in the first quarter, which is reflected in our guidance. 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, but realizations improve rapidly with higher prices as we saw in the fourth quarter and continue to see in the first quarter.

Given gas prices exhibit seasonal volatility, we expect our realizations to follow a similar pattern and to be weaker in the second and third quarters and stronger in the first and fourth. The net impact of seasonality is reflected in our full-year guidance, with the first quarter realizations exceeding the full-year expectations. Turning to operating costs, fourth quarter LOE was below our expectation at $9.60 per BOE, reflecting better downtime and lower workover costs. 2025 LOE guidance reflects modest escalation relative to 2024, but this may prove conservative as it did in 2024 depending on downtime and workover spend levels. Fourth quarter cash GPT was $2.86 per BOE, in line with our guidance. Fourth quarter cash G&A was $31.2 million, excluding $9 million of merger-related costs, and quarterly G&A is expected to continue to trend downward in 2025 as we realize further synergies.

Production taxes averaged 8.4% of commodity sales in the fourth quarter, and cash taxes were in line with our expectations. We expect full-year 2025 cash taxes to approximate 3% to 10% of EBITDA and first quarter cash taxes to approximate 1% to 7% of EBITDA each at oil prices of $60 to $80 per barrel. Fourth quarter adjusted CapEx of $325 million excludes $5.2 million of reimbursed non-operated capital and was $10 million below midpoint guidance, largely reflecting minor shifts in timing to 2025. Even with this shift, we are still planning on investing $1.4 billion in 2025, and $365 million of that is in the first quarter. In February 2025, the company completed its semiannual borrowing base redetermination, setting the borrowing base at $2.75 billion and increasing the aggregate amount of elected commitments to $2.4 billion.

As we returned 100% of our free cash flow to investors across the quarter, separately, we layered on some hedges since our last update. Our derivative position as of February 4th can be found in our latest investor presentation. In closing, thanks again to the Chord team for all their hard work on the integration front and for the intense focus on improving day-to-day operations. We are pleased with the substantial progress that we’ve made over 2024, the continued performance of the team, and the position that they put the organization in to succeed going forward. So with that, I’ll hand the call over to Andrew for questions.

Operator: Thank you. Ladies and gentlemen, should you have a question, please press the star followed by the number one on your touch-tone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number two. If you are using a speakerphone, please lift the headset before pressing any keys. One moment, please, for your first question. Our first question is from Scott Hanold from RBC. Please go ahead.

Scott Hanold: Yeah. Hey. Thanks all. Can you give, you know, just some context around your outlook for capital in 2025 and maybe even go forward? I mean, there’s obviously, you have a low and a high end of the range. But can you just give us some sense of what, you know, could drive you to the lower end of the range this year? Is it, like, increasing just to simulfrac, or just more experience with that? And, you know, what is the potential to see downside pressure on that $1.4 billion kind of three-year outlook?

Danny Brown: Hey, Scott. It’s Danny. Thanks for the question. So, you know, we look at 2025, we are always going to provide ranges around these things. I do think, as you know, when we put this out in, you know, November of last year and as we’ve rolled forward that plan, we’ve taken a somewhat static view and don’t include improvements in efficiency, cycle times, that sort of thing. In this. And so to the degree we see incremental improvements on that, and candidly, we see that year on year, industry does, and we certainly do too. That will roll through to the benefit of the overall program. Again, we like to be slightly conservative on these things, and my expectation is we’ve got probably more downward pressure than upward pressure on that number.

Certainly, we’ll work through the year. I’ve mentioned before, we do like to have, you know, from a service standpoint, we do like to always be in the market a bit. So we’ve always got contracts rolling off and on, and those things can move either direction. I’ll tell you where I sit now relative to commodity and activity levels. I think we’re probably flat, maybe some looseness in that along certain line items. So a number of things could drive us lower. I think importantly, if we see better well performance, that’s another thing that could drive us lower because we’re really not trying to chase capital up. The intent is to drill to deliver a maintenance production level. And if we see our wells performing stronger and hanging in, and we certainly have seen in the past encouraging things along those lines, we’d probably let capital float down a little bit to maintain that production level.

So I think we’ve got several things that could push it down. Over a three-year time frame, to the second part of your question, as Darrin mentioned, this was all a static look, improving no. As we will continue to get better just on the existing three-mile and two-mile legacy developments, all of that will inure to the benefit of the capital program in sort of the out years 2026 and 2027. So when we rolled that out, we said we thought it was a little conservative, and we weren’t putting something out there that we didn’t have high confidence we could meet or exceed, and I still feel the same way.

Scott Hanold: Okay. That’s appreciate that. And part of that too and, you know, I hate to try to layer another question there, but I guess I missed it if you said it. But is the simulfrac, you know, your current pace of is it basically doing full simulfracs for the year? Is that included in the plan as well?

Danny Brown: Well, we’ve got the, on, I mentioned we’ve got one partial crew and one full crew. We’re doing simulfracs with the full crew. We’re actually doing, we’re not necessarily doing simulfracs with that partial crew. And so, you know, for that full crew, that is all assuming simulfrac. But as that efficiency improves, clearly, you see some benefits. You can see some benefits from that. But I think we’ve got a lot of that baked in.

Scott Hanold: Okay. Got it. And then for my follow-up question, can we touch on shareholder returns? I mean, obviously, giving 100% of free cash flow was very robust in all buybacks. Like, look, your stock’s up today, but it’s still quite a bit under where you did your buyback in the fourth quarter. I mean, should we look at that as pretty indicative of what you all might do going forward here, especially with your very low leverage? Does it make sense to continue to kind of push it towards that 100% and all incrementally being buybacks?

Danny Brown: Well, what I’ll say, Scott, is that we have, at the end of the day, it’s really a capital allocation decision. And as we look at that sort of incremental free cash flow generated above 75%, we have to think about what we do with it. And with our leverage position where it is, you know, sort of retiring from that, that doesn’t make a lot of sense, and we see our shares at this level as a really compelling capital investment opportunity. Thank you.

Operator: Your next question is from Derrick Whitfield from Stifel. Please go ahead.

Derrick Whitfield: Good morning, Owen. Thanks for taking my questions.

Danny Brown: Thanks, Derrick.

Derrick Whitfield: Regarding three-mile laterals, I want to thank you for your disclosures on slides nine and ten as it’s been quite challenging to compare well productivity per foot between two and three-mile laterals when there are over four variables you have to control for that analysis. Maybe setting aside cost for a moment, where are you seeing the QM curves per foot meaningfully start to converge in the life of the well? And then specific to cost, are you seeing better cycle times with three-mile laterals given the benefit of additional reps?

Danny Brown: So I’ll start with the latter first. So we absolutely are doing these things faster. And I think with like anything, as you get more practice, you get better and better at them, and we’re certainly seeing that with three-mile laterals, not just with drilling and completion. But I think importantly, getting cleaned out to toe and not just the cycle times, but the cost associated with getting down to the toe of the well to clean that out. With respect to convergence on an EUR per foot basis, I think it’s, you know, after about six months, we start to see that converge pretty well. We’re getting to sort of till the 95% on an equivalent basis of two on a per foot EUR recovery. After around six months, and you’re essentially all the way there within a one-year time frame.

So, you know, that first three or four months is really where you see the difference in the QME URs. And so if you’re focusing on that very early well-timed data, it can be misleading, as Darrin pointed out. But within about six months, you’re there, and you’re all the way there within a year.

Derrick Whitfield: Terrific. And then regarding your first four-mile lateral, could you speak to what operational challenges you observed, if any, and then what do you see as the cost benefit for transitioning from three-mile to four-mile laterals after accounting for the cycle times?

Danny Brown: I’m going to ask Darrin to respond to that because he’s been real close to this first well, as you can imagine.

Darrin Henke: Yeah, Derrick, knock on wood, for the first four-mile well has really gone off without a hitch. We spud rig release was fourteen and a half days, the fastest well spudded in the basin four-mile lateral at this point. And then the frac job went beautifully. Being able to pump the frac stages at the toe, we were somewhat concerned about what kind of rate would we be able to get, you know, going through all that pipe with the friction losses, but all that went really well. And we just, as of this morning, we just reached TD drilling out the frac plugs, and we’re able to do that in one run as well. So boy, like I say, knock on wood, operationally, it’s gone very well. We see similar to get to the second part of your question, you know, relative to the performance of a four-mile well, we think we’ll see the same kind of uplift going from three miles to two miles, we’ll see similar uplifts going from four miles going from three miles to a four-mile well.

And we’re also looking at a lot of alternate shapes. People have different names for them in the basin, but we’re looking at ways to really dramatically change our inventory to three miles and four miles and perhaps down the road even beyond that. So a lot of work going on there, and none of that, as Danny said, is in our three-year plan. It’s not baked into our long-term inventory either at this point.

Derrick Whitfield: Great update. Thanks for your time.

Darrin Henke: Yes, sir.

Operator: Your next question is from Neal Dingmann from Truist. Please go ahead.

Neal Dingmann: Good morning. Thanks for the time, guys. Again, my question is just now with the integration, I guess, really my question is on just your operational efficiencies for you or Darrin. You continue to, you know, see the improvement not only going from the two to three miles and three to four miles. I’m just wondering when you sort of see things set up this year, can you continue to sort of chip away at that? And if so, where do you think some of those, you know, efficiency gains will be coming from?

Danny Brown: So, Neal, appreciate the question. You know, it’s again, with incremental reps, you just get better. And so, you know, we’re starting to get some reps under our belt from a three-mile perspective, and we’ve seen that happen. Certainly, we saw a dramatic improvement last year from an efficiency perspective as we moved to the and adopt the simulfrac across the fleet. So I think you’ll see us continue to grind down incremental improvements on three miles. We’re at serial number one of a four-mile. And so we got plans to do a few more of those over the course of the year, and I think you’ll probably see dramatic improvement on those even with the strong start that Darrin just mentioned. And so I’m sure the program won’t be without its hiccups.

They all are. But what we know is as we get more practice on these things and we do more, we seem to drive efficiencies pretty quickly into the programs and far surpass our original expectations going in. At least that’s been my history with this industry and with this organization. So I think we’ll again, you’ll see sort of the steady incremental improvements on the three-mile, probably significant improvements on the four-mile, which as we’ve talked about, this four-mile program is really contemplated early on to replace two-mile wells. If we’re able to see, you know, sort of consistent delivery and uplift, you could see us start to replat some of these three miles to take advantage of the four-mile uplift as well.

Neal Dingmann: I like that upside. And then, again, just a question on M&A. Is, you know, is it fair to say that I think you’ll have, you know, ample more certainly ample inventory. But with that said, pristine balance sheet, I mean, again, I guess my question is what does the M&A landscape sort of look like to you today and, you know, how actively do you think, you know, you all could be out there doing something?

Danny Brown: Well, to your point, Neal, I think we are we think we’ve got a great inventory set here, far better than what we often feel like we get credit for. So I’m happy with the inventory position. And I’ve like I’ve said, it’s not just about we do think there’s advantages scale in this industry, but at the end of the day, the size has to make you better, not just bigger. And you’ve seen us be, I’d say, patient. And we’ve picked our spots on where we have decided to do M&A. And I think you’ll see us continue to do that. And if we see a way that we think delivers true shareholder value through an M&A transaction, that’s something obviously we’ll evaluate because that’s what we want to do is to deliver value to shareholders. But it has to do that at the end of the day. So I think you’ll continue to see us be patient, and if we do something, we’ll recognize that it has to be something that delivers the loads full cycle value.

Neal Dingmann: That makes sense. Thank you so much.

Danny Brown: Thank you.

Operator: Your next question is from Oliver Huang from TPH. Please go ahead.

Oliver Huang: Good morning all, and thanks for taking the questions. Just wanted to kind of start out on gas and NGL realization. I know in the prepared remarks, you kind of alluded to a fixed component there. And I see that you all have underwritten $3.50 in your outlook. Just thinking, if we’re seeing some sort of upside to gas prices towards four bucks in 2026 or an improvement in the AECO market, is there any sort of rule of thumb or sensitivity in terms of what sort of uplift we might see for your cash flow streams?

Michael Lou: Yeah. I mean, I think that’s a great question. You’re spot on that, you know, as the price starts to tick up, you’ll continue to see, you know, us tick up. I think the thing to watch for is, like, what’s happening with NGL prices at the same time because you’ve, you know, you’ve seen that as well because we’re allocating it to both gas and gas and NGL. But you’re definitely right as gas prices go up, we’ll be scaling incrementally to capture that value.

Oliver Huang: Okay. Makes sense. And maybe just on the non-op side, I know there isn’t always great line of sight to when the activity shows up. But just kind of given how it’s being flagged with a decent magnitude out of the Williston, any sort of color you’re able to speak to on who the primary operators that we should be aware of for this year, if there’s any specific part of the basin the activity is likely to be concentrated in or if it takes a roughly similar mix versus what we’ve kind of seen from your operated portfolio.

Michael Lou: Hey, Oliver. This is Michael. Good question on the non-op side. We’re seeing a good mix of operators really across the basin, so you can kind of look at basin activity as a whole, and our non-op program is probably a proxy for that. Overall, you know, activity continues to be in the core kind of part of the basin overall, so we’re still seeing quite a bit of that activity in very good parts of the basin. I think it’s very similar returns to our operated program. So I don’t think you’ll see any kind of diminishment of returns or anything like that that we’re expecting across the program. So really good returns on both the operating side and the non-operated side. So we’re excited about the program. We’re seeing activity from a bunch of other operators.

We think we can learn from them as well. So we’ll be continuing to watch data to make sure that, yeah, there’s a lot of people testing different things across the basin. Not as many people talk about them because they’re in some bigger companies, but we’ll be watching it closely and making sure that we continue to improve our operations on that front as well.

Oliver Huang: Makes sense. Thanks for the time.

Michael Lou: Thank you.

Operator: Your next question is from John Abbott from Wolfe Research. Please go ahead.

John Abbott: Good morning, and thank you for taking our questions. My first question is on tariffs. It’s not on the cost side, but if tariffs were implemented, how do you think the impact would be to your oil and gas NGL realizations?

Danny Brown: John, this is Danny. Thanks for the question. You know, I think in general, when you think about tariffs, when a tariff is implemented, generally, it’s to the benefit of the domestic producer. And I don’t think it would probably be much different here. I think, from a refining, from an oil perspective, you know, there’s probably some level of incremental pain felt by the refiners and the foreign producers and maybe a small incremental benefit to the domestic producer. I don’t think it’s dramatic, but I think that’s probably you probably see a small incremental pull for the domestic barrel. And so that’s kind of how we think about it. Now, what I can’t say is what the butterfly effect of tariffs do. We may see slightly a slight pull from a demand side on our barrels, which should put some upward pressure on pricing there, to what degree, I’m not sure.

But then it has a broader effect too. It has to affect overall demand, where do prices go from just the supply-demand perspective? So lots of moving parts there, but just on its pure, if you isolated that one thing, I think probably an incremental pull on domestic barrels.

John Abbott: Appreciate it. And then for our follow-up question, I mean, we’ve seen the improvement in natural gas prices. What are your latest thoughts on maintaining your non-op Marcellus position?

Danny Brown: Well, we think we’ve got a we have been the beneficiary in both Williston and in for the non-op production we have in Marcellus of the higher natural gas prices here, recently. We think Marcellus is a it’s a great asset. It is under a very capable and good producer. As we’ve mentioned before, it’s not a core portion of the Chord portfolio, and we’re going to look to see how do we maximize value delivery to shareholders from that asset over time.

John Abbott: Thank you very much for taking our questions.

Danny Brown: Thanks, John.

Operator: Your next question is from Josh Silverstein from UBS. Please go ahead.

Josh Silverstein: Hey, thanks. Good morning, guys. Just wanted to follow-up on buyback. I know you were at 100% this quarter, but would you guys consider using the balance sheet to go above 100% just given where the stock is trading at? Just I’m just curious given the valuation of the stock. Thanks.

Danny Brown: Yeah. Appreciate it, Josh. As I said, it’s really a capital allocation decision for us. And so, you know, you’ve seen us in the past use the balance sheet to make compelling capital allocation decisions. And so I’ll sort of leave it at that. You know, ultimately, we’ve got to weigh, you know, increasing leverage relative to capital investment opportunities, etcetera, but it’s something clearly we talk about, and we do think our shares are pretty compelling where we’re at right now.

Josh Silverstein: Got it. And then just on the inventory duration, I know you mentioned around ten years before, and that’s somewhat of a third-party estimate, but could you go into what you guys are assuming from an inventory standpoint? You know, does ten years assume three miles? How many, you know, wells in the middle bucket? Is there anything left in the three forks just to kind of give more color around that?

Danny Brown: Yeah. I’d say our inventory, I think, is fairly conservative, Josh. It’s essentially a middle Bakken only program. We’ve got very little three forks. There’s a little bit, and we’re talking small single-digit percentage in our inventory that’s associated with three forks. So it’s really a middle Bakken program, pretty conservatively spaced program. And yeah. So, you know, as we are able to potentially see some of these longer laterals convert areas of the field because of the improved economics into areas that actually become nice and attractive investment opportunities, we have the potential to see this march higher. And candidly, to the degree that we determine that maybe we’re a little too loose in our spacing in some areas, we could see some more inventory come in as a result of that as well.

I will tell you, it is not I want to effectively drain the resource with as few straws as possible because that’s the most capital-efficient way to do it, and that’s going to be what delivers us the strongest returns. And so we are not into manufacturing inventory, but if it determines that, you know, if we determine that we are too loose and we’re leaving resource in the ground that offers strong returns, then we’ll look at maybe tightening up our spacing a bit. I don’t think that will be dramatic. When you consider our 1.3 million acreage position up there, even a small sort of tightening of spacing has a not immaterial impact on overall inventory. So, you know, I’d say our sort of in summary, I’d say our inventory, we see it as maybe somewhat conservative, and I’ll leave it at that.

Josh Silverstein: Thanks.

Operator: Your next question is from Paul Diamond from Citi. Please go ahead.

Paul Diamond: Thank you. Good morning. I was just taking the call. So you talked about the conversion and general conversion of two two-mile DSUs, three-mile to one four-mile, but also that opportunity set to kind of extend the three-mile inventory. That’s currently 60% of your inventory set. I wanted to see if you could kind of dial in, you know, how much of that 60% is potentially convertible at all and just matters on the economics as well or just kind of how to think about that.

Danny Brown: Yeah. I’d say, generally speaking, Paul, you know, we think we’ve got sort of, I’d call it, greater than, greater than 50% from a three-mile inventory perspective currently. And so then there’s a balance that is part, you know, part of the balance is two-mile inventory. We’ve got some that are, you know, actually lower than that, and then we’ve got some areas where we may have some four-mile opportunities. And so it’s a mix outside that 50%. Our goal would be and our objective would be to get, you know, up to around 80% into that three-mile plus sort of space. And so we actually have to slide in our investment deck where I think we talk about what our objective is. And maybe our objective is to get it to you actually even higher than 80% candidly, but we recognize there’s going to be some areas where we’re landlocked.

It may be somewhat difficult to do that. So but I think as an aspirational goal for ourselves getting to 80% three-mile or greater, is something we’re certainly shooting for. As we are able to see strong performance from a four-mile well, if and when we see that, then I think we’ll really go back to the drawing board from our overall DSU layout and say, where can we re-space some of these three miles to four miles to see the upside? So that we need to get this first well producing. We need to get a few more wells in the ground before we really undertake that effort because, as you can imagine, replanting out the whole basin, not a trivial thing to do, and we need to see some results first.

Paul Diamond: I don’t know. Maybe midyear. You’re talking about just the timing of that. What could cause it to kind of be pulled forward or pushed back and how that really pertains into the trend of CapEx for the year. That should be I know we should expect to be front half-weighted, but is that more Q1 than the kind of how to think about the timing of all this?

Darrin Henke: Yeah. The fifth rig we’re looking at letting go plus or minus midyear at this point. So not I don’t you’ll see a lot of impact to 2025 production associated with that rig. With that rig getting laid down. You know, what could change the timing on that rig? Just well productivity. You know, if we see better improvements in run time than what we forecasted in our plan. So we need less production from the wedge, then you could maybe see us release that rig earlier. That’d be a positive thing for the overall program and, while our production team is focused on that every day, working to improve our run times minimize downtime. So that’s a lever a lot of people don’t think about relative to the capital program and maintaining. That’s a color that we can share with you at this time.

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

Operator: Your next question is from Noah Hungness from America. Please go ahead.

Noah Hungness: Morning, guys. For my first question, I wanted to ask. We’ve seen some competition on the midstream side in the Bakken, and I was just wondering, is there a read-through here for you all that maybe you guys could renegotiate or have or have lower GP and T costs?

Danny Brown: Well, Noah, I’d say that we’re always looking at opportunities to make sure that we’re getting the best price and the best net back pricing. And so we have, you know, we’ve got contracts in place as those roll off. Clearly, we’re going to negotiate hard to get the best deal for ourselves. Say even before some of those contracts roll off, we have opportunities as we’ve grown and scale where we can, you know, there may be things that we can do that are win-wins for both organizations that, you know, even while we’re under contract, that can make things better for us as we move forward, and we’re always looking at those things. I’ll ask Michael to add any incremental comments he’s got.

Michael Lou: Yeah. No. I mean, they’ll he kind of mentioned it. There’s a lot of competition. There’s pretty mature systems out there across water, gas, oil, kind of all the different pipeline pieces, which just create competition, which is fantastic for us. We got a big program that spreads kind of throughout the basin. So there are a lot of options for us in the basin. And as you mentioned, very competitive. So hopefully, all those costs, we can continue to work on as Danny mentioned.

Noah Hungness: That’s great to hear. And then for my second question, I wanted to ask on the non-op Marcellus. As we’ve seen gas prices ramp up here and the gas macro looks more and more attractive, what kind of gas production are you guys baking into your 2025 corporate guidance from that non-op Marcellus position?

Danny Brown: Yeah. This is Danny again. So, you know, currently, we’re thinking, you know, between 130 to 140 million cubic feet coming through that coming through our non-op position there in Marcellus.

Noah Hungness: Is there any just as a quick follow-up or clarification, is there any seasonality in that production profile this year?

Michael Lou: Yeah. In general, it’s going to be relatively flat. You are seeing that grow a little bit here, obviously, with the gas price coming up. At the end of last year into the early part of this year, you’re going to see a little additional activity. We’ll see where that continues to hold from a gas price scenario that there is a lot of kind of activity in the area. And I think that those as you’re seeing across all gas basins, you’re seeing activity come up with that gas price. So there is potentially some upside there if you see gas prices hold at a good level. Great, great returns. So fantastic rock. Great returns. So we’re really excited from a capital allocation standpoint to put it there if gas prices hold kind of where they’re at or better.

Noah Hungness: Sounds good. Thanks for taking our questions.

Danny Brown: Thank you. Thanks, Noah.

Operator: The next question is from David Deckelbaum from TD Cowen. Please go ahead. Once again, the next question is from David Deckelbaum from TD Cowen. Please go ahead.

David Deckelbaum: Thanks for getting me on, guys. And good morning to you all. I wanted to ask just to follow-up on the Marcellus. You know, how do you think about that position, I guess, strategically now? And, you know, is this something that you might view as a source of funds over the next couple of years just, again, given the prevailing price there and obviously the non-op position, you know, you’ve been able to take advantage of attractive share buyback opportunities right now. And, arguably, maybe that’s an asset that you’re not getting credit for. Is that something that’s under serious consideration just with the improvement in the gas strip?

Danny Brown: Hey, David. This is Danny. So I’ll say that, you know, as we said, we think that’s a great it’s a great asset. It’s got strong returns associated with it. It’s under a great operator, but it’s not core to our portfolio. And so we’ve acknowledged that that’s not a core position for us, and what we want to do is maximize value delivery to shareholders out of that asset. And one option, obviously, that we’re thinking about is, you know, a potential monetization there and then what we do with the again so any proceeds we would get out of that would be a capital allocation decision for ourselves at that moment.

David Deckelbaum: I appreciate that. And then just curious as to as we think about capital efficiency improvements, you know, in 2025 versus 2024, I guess, that you guys highlighted. You know, are you is this are you more or less holding productivity flat and just assuming, you know, obviously increases in lateral length, but improvements in incremental cycle times? Because I think it was obviously you guys have highlighted the relative improvement in cycle times to peers, you know, in 2024. But I guess, like, how do you think about just capturing efficiencies with longer laterals as it relates back to just cycle time improvements?

Danny Brown: Well, the three-year plan we have currently and kind of how we’re viewing the 2025 program doesn’t incorporate a whole lot of incremental improvements relative to where we were, I would say, toward the back half of last year. And so that program, any incremental efficiency gains that we find, should roll straight through to sort of improving our overall ability to deliver ultimately free cash flow, both this year and over the three-year time frame. So, you know, my expectation is as we see those efficiencies roll through, so for ourselves and incremental free cash flow from that lower CapEx level. But again, we’ve put out both for 2025 and for the three-year plan. We want to make sure we’ve got something out there that we can achieve or beat. And I feel, because we’ve got these efficiencies still in.

David Deckelbaum: Thanks, Danny. Appreciate it.

Danny Brown: Thanks, David.

Operator: Your next question is from Noel Parks from Brothers Investment Research. Please go ahead.

Noel Parks: Hi. Good morning. Just had a couple of things. You know, one thing just trying to really wrap my head around the whole notion of four-mile laterals. As far as you know at this point, are there any new or unexpected frac protection issues introduced when you’re doing four milers? I mean, I guess, specifically, you know, like a horseshoe shape or is it really just essentially the same as, you know, a pad with multiple two milers?

Danny Brown: Yeah. So no really incremental frac protect issues that we can think of. And the four milers we’re looking at doing now are really straight four milers. And so it’s which we think is the most efficient way to do things. We do look at alternate well shapes if we can’t go to a straight, we’ll look at alternate because we recognize that capital efficiency of that incremental foot of lateral is almost always going to be better, but the best incremental foot is going to be a straight incremental foot. And so as we’re looking at four miles, that’s really what we’re doing right now. A straight four miles and no difference in frac protect concerns relative to what we would see if you were doing two two milers.

Noel Parks: Great. Thanks a lot. And one thing, just looking at the reserves, was there Enerplus from the Enerplus locations, any reduction in industry sorry, inventory that pushed out in the five-year CapEx rule? And just curious if as far as Enerplus, everything is really planning to do as far as high grading is essentially done at this point with the integration.

Danny Brown: Yeah. So as we brought the Enerplus reserve over into our system, clearly, we had to follow US and SEC rules as opposed to Canadian rules that Enerplus followed. So that rolls through. We also like to we generally take a bit of a conservative stance on our PUD bookings, and so we’re not fully booked out to the five years. And that’s just been a long-standing practice of the organization. And so yeah. So the reserves we released incorporate both those effects.

Noel Parks: Great. Thanks a lot.

Danny Brown: Fantastic. Thanks, Noel.

Operator: Pause a moment for any further questions. There are no further questions at this time. I will now turn the call over to Danny Brown with closing remarks.

Danny Brown: Alright. Thanks, Andrew. Well, to close out, I want to thank all of our employees for their continued hard work and dedication. Our strategic actions, coupled with our fantastic operations team, have created what we believe is a valuable and increasingly rare asset. Chord has a substantial yet low decline in 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. With that, I appreciate everyone’s interest, and thanks for joining our call.

Operator: Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.