Chord Energy Corp (CHRD) 2024 Q4 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the Chord Energy fourth-quarter 2024 earnings call. (Operator Instructions) 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.

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; and 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.

Thanks, Bob. Good 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 as 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, which allowed us to capture substantial operational and corporate synergies. And notably, we executed this transaction while maintaining our commitment to balance sheet strength, capital discipline and peer-leading return of capital. My sincere thank you to all the employees who, through their commitment and dedication have placed us in a great position to succeed.

And to that point, I believe this is the best position the company has been in since I arrived 4 years ago. Chord has 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've 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. And 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 6 of our presentation, where we show that Chord has grown oil production per share at a 12% compounded annual growth rate over the last 3 years. And importantly, we did this while simultaneously preserving our balance sheet and paying out approximately $2 billion in dividends. Given our strong inventory and low reinvestment rate and what we see as a compelling valuation on both an absolute and relative basis, which we highlight on Slide 4, 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 execution and well performance, while 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. My 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 multiyear 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 5 rigs, which we expect to decrease to 4 by midyear. Additionally, we are currently running 1 full-time frac crew and 1 spot crew. We expect to turn in line between 130 to 150 gross operated wells in 2025, including 22 to 32 in the first quarter. The remainder of 2025 TILs 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 3-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 with 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 or 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 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.

In Slide 7 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, where 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.

And 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. 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. 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 with 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.

Thanks, Danny. Operationally, Chord continues to hit our stride, and we're off to a great start on our 3-year plan issued in November. We view this 3-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 3-mile laterals or 4-mile laterals, all of which are focal points for the organization. Currently, the 3-year plan projects over 50% to be 3-mile laterals, and Chord's total inventory is over 60% 3-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 3-year plan and our overall inventory. Just a quick update on 4-mile laterals. Chord successfully drilled and completed our first 4-mile lateral, and we just reached a TD exceeding 30,400 feet while cleaning out the frac plugs. We're planning several more 4-mile laterals in 2025 and with success, are likely to implement many more in 2026 and beyond. As a reminder, our initial approach to 4-mile wells will be converting 2 2-mile DSUs to 1 4-mile DSU.

However, similar to Chord's evolution on a 3-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 3-mile inventory into 4-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 9 highlights the economic benefits of 3-mile laterals, which delivered 50% more EUR than 2-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 2-mile wells in the core and shifted towards more 3-mile wells on its western acreage.

On the lower right-hand side of Slide 9, you can see a contrast between a 2-mile core well and a 3-mile well on our Western acreage. The F&D cost for the Western 3-mile well is actually better than the core 2-mile well as lower D&C cost per foot more than offset the lower EUR per foot. Said another way, longer laterals outside the core actually have similar or better returns than 2-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 3-mile well will deliver a slightly higher IP, stay flat longer and exhibit shallower declines than a 2-mile well. When comparing analog well performance per foot of lateral, initially, 3-mile wells typically will typically be lower than 2-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 3-mile well to catch up to the 2-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 flowback 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, per foot performance is the appropriate way to judge well productivity over the long term, but early data is often misleading. On Slide 10, 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 of the program. As you can see, the 2024 program is superior to 2023, and we expect the 2025, '26 and '27 programs at a minimum to deliver similar capital efficiency as 2024. Turning to inventory.

Slide 5 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 3-mile wells by about 1.5 days in 2024 versus 2023 and regularly set new records on the Enerplus acreage. On the completion side, our full-time frac crew is using simul-frac operations on most pads, which has driven down nonproductive 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 our delivery. I'll now turn it over to Richard.

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, while total volumes were above the top end, reflecting strong well performance. Oil realizations 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% of WTI in the fourth quarter, near the top end of our guidance range. Natural gas realizations were stronger than expected at 43% of Henry Hub. Realized gas prices in the Bakken benefited 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 improved rapidly with higher prices as we saw in the fourth quarter and gradually over the course of 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 nonoperated 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 annual -- semiannual borrowing base redetermination, setting the borrowing base at $2.75 billion and increasing the aggregate amount of elected commitments to $2 billion. As of December 31, 2024, Chord had $445 million drawn under its revolver, $400 million of senior unsecured notes, $37 million of cash and $31 million of letters of credit. Net leverage remained at 0.3x at year-end 2024 as we returned 100% of our free cash flow to investors across the quarter. Separately, Chord layered on some hedges since our last update. Our derivative position as of February 24 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 Instructions) Scott Hanold, RBC.

Can you give us some context around your outlook in -- for capital in 2025 and maybe even going forward? I mean there's -- obviously, you have a low and high end of the range. But can you just give us some sense of what could drive you to the lower end of the range this year? Is it like increasing just the simul-frac or just more experience with that? And what is the potential to see downside pressure on that $1.4 billion kind of 3-year outlook?

Scott, it's Danny. Thanks for the question. So as we look at 2025, we're always going to provide ranges around these things. I do think is when we put this out in 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 things 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.

So 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 -- from a service standpoint, we do like to always be in the market a bit. And 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 3-year time frame to the second part of your question, as Darrin mentioned, this was all a static look, improving no efficiencies relative to November of last year. And so as 4-mile laterals may come into the program, as we will continue to get better just on the existing 3-mile and 2-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 going to put something out there that we didn't have high confidence we can meet or exceed, and I still feel the same way.

Okay. That's -- I appreciate that. And part of that, too, I hate to try to layer another question here, but I guess I missed it if you said it, but is the simul-fracs -- your current pace of -- is it basically doing full simul-fracs for the year? Is that included in the plan as well?

Well, we've got on -- I mentioned we've got 1 partial crew and 1 full crew. We're doing simul-fracs with the full crew. We're actually doing -- we're not necessarily doing simul-fracs with that partial crew. And so for that full crew, that is all assuming simul-frac. But as that efficiency improves, clearly, you can see some benefits from that.

But I think we've got a lot of that baked in.

Okay. 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 buybacks in the fourth quarter. I mean does that -- 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?

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 the 75%, we have to think about what we do with it. And with our leverage position where it is sort of retiring incremental debt doesn't make a lot of sense, and we see our shares at this level as a really compelling capital investment opportunity.

Derrick Whitfield, Texas Capital.

Regarding 3-mile laterals, I want to thank you for your disclosures on Slides 9 and 10 as it's been quite challenging to compare well productivity per foot between 2 and 3-mile laterals when there are over 4 variables you have to control for that analysis. Maybe setting aside cost for a moment, where are you seeing the [chem] 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 3-mile laterals given the benefit of additional reps?

So I'll start with the latter first. 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 3-mile laterals, not just with the 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 -- after about 6 months, we start to see that converge pretty well. We're getting to sort of TIL the 95% on an equivalent basis of 2 -- on a per foot EUR recovery after around 6 months, and you're essentially all the way there within a 1-year time frame.

So that first 3 or 4 months is really where you see the difference in the Q EURs. And so if you're focusing on the very early well time data, it can be misleading, as Darrin pointed out. But within about 6 months, you're there and you're all the way there within a year.

Terrific. And then regarding your first 4-mile lateral, could you speak to what operational challenges you've observed, if any? And then what do you see as the cost benefit for transitioning from 3-mile to 4-mile laterals after accounting for the cycle times?

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

Yes, Derrick, knock on wood for the first 4-mile well has really gone off without a hitch. We spud rig release, was 14.5 days. The fastest well suspended in the basin 4-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 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 like I say, knock on wood, operationally, it's gone very well.

We see similar -- to get to the second part of your question relative to the performance of the 4-mile well. We think we'll see the same kind of uplift going from 3-miles to 2-miles. We'll see similar uplift going from 4-miles going from 3-mile to a 4-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 3-miles and 4-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 3-year plan is not baked into our long-term inventory either at this point.

Great update. Thanks for your time.

Neal Dingmann, Truist.

My question is just now with the integration, I guess, really my question is on just your operational efficiencies for you and Darrin. You continue to see the improvement now going from the 2 to 3-miles and 3 to 4-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 efficiency gains will be coming from?

So Neal, I appreciate the question. It's -- again, with incremental reps, you just get better. And so we're starting to get some reps under our belt from a 3-mile perspective. And so we've seen that happen, Certainly, we saw a dramatic improvement last year from an efficiency perspective as we move to the -- and adopt simul-frac across the fleet. And so I think you'll see us continue to grind down incremental improvements on 3-miles.

We're at serial #1 of a 4-mile and so we've 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 surpassed 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 a steady incremental improvements on the 3-mile probably significant improvements on the 4 mile, which as we've talked about, this 4-mile program is really contemplated early on to replace 2-mile wells. But if we're able to see sort of consistent delivery and uplift, you could see us start to relate some of these 3-miles to take advantage of the 4-mile uplift as well.

Kinda like that upside. And then Danny, just a question on M&A. As it stand same I think you'll have 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 how actively do you think you all could be out there doing something?

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. And so I'm happy with the inventory position. And like I've said, it's not just about -- we do think there's advantages to 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 what -- 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 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 cycle value.

Oliver Huang, TPH.

Just wanted to kind of start out on gas and NGL realizations. I know in the prepared remarks, you kind of alluded to a fixed component there. And I see that you all have underwritten 350 in your outlook. Just thinking if we're seeing some sort of upside to gas prices towards $4 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?

Yes. I mean I think that's a great question. You're spot on. As the price starts to tick up, you'll continue to see 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 seen that impact as well because we're allocating both gas and NGL.

But you're definitely right. As gas prices go up, we will be scaling incrementally to capture that value.

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 the 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 is 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?

Yes, 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 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 terms on both the operating side and the nonoperating 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 there's a lot of equal testing in different things across the basin. Not as many people talk about them because they're in some bigger companies.

We'll be watching it closely and making sure that we continue to improve our operations on that front as well.

John Abbott, Wolfe Research.

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?

John, this is Danny. Thanks for the question. 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, there's probably some level of incremental pain felt by the refiners and the foreign producers and maybe 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 from the domestic barrel. And so that's kind of how we think about it. Now what's -- what I can't say is what the butterfly effect of tariffs do. We may see 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, how does it affect overall demand, where does the -- and where the prices go from just a 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.

Appreciate it. And then for a follow-up question, I mean, we've seen the improvement in natural gas prices. What is your latest thoughts on maintaining your non-op Marcellus position?

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

Josh Silverstein, UBS.

Just wanted to follow up on the buyback. I know you were at 100% this quarter, but would you guys consider you use the balance sheet to go above 100%, just given where the stock is trading at? I'm just curious given the valuation of the stock.

Yes. I appreciate it, Josh. As I said, it's really a capital allocation decision for us. And so you can see -- you've seen this in the past, use the balance sheet to make compelling capital allocation decisions. And so I'll sort of leave it at that.

Ultimately, we've got a way increasing leverage relative to capital investment opportunities, et cetera, but it's something clearly we talk about, and we do think our shares are pretty compelling where we're at right now.

Got it. And then just on the inventory duration, I know you mentioned around 10 years before. I know it's somewhat of a third-party estimate. But can you go into what you guys are assuming from an inventory standpoint? Does 10 years assume 3 miles, how many wells in the Middle Bakken?

Is there anything left in the Three Forks, just to kind of give a more color around that.

Yes. 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 -- 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 yes, so 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 capitally 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 -- 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. But when you consider our 1.3 million acre position up there, even a small sort of tightening of spacing has a not immaterial impact on overall inventory. So 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.

Paul Diamond, Citi.

So you talked about the conversion -- general conversion of 2, 2-mile DSUs to 1, 4-mile, but also that opportunity set to kind of extend the 3-mileinventory, that's currently 60% of your inventory set. Just wanted to be kind of dial in how much of that 60% is potentially convertible? Is it all and it just matters on the economics of the well or just kind of how to think about that?

Yes. I'd say, generally speaking, Paul, we think we've got sort of, I'd call it, greater than 50% from a 3-mile inventory perspective currently. And so then there's a balance that is -- part of the balance is 2-mile inventory. We've got some that are actually lower than that. And then we've got some areas where we may have some 4-mile opportunities.

And so it's a mix outside that 50%. Our goal would be and our objective would be to get up to around 80% into that 3-mile plus sort of space. And so we actually have a slide in our investor deck where I think we talk about what our objective is. And maybe our objective is to get it actually even higher than 80%, candidly, but we recognize there's going to be some areas where we're pretty -- we're landlocked. It may be somewhat difficult to do that.

So -- but I think as an aspirational goal for ourselves getting to 80%, 3-mile or greater is something we're certainly shooting for. As we are able to see strong performance from a 4-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 respace some of these 3 miles to 4 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, replating out the whole basin is not a trivial thing to do, and we need to see some results first.

Understood. (inaudible) clarity. Just a quick follow-up. You all talked about dropping a rig midyear. You're talking about just the timing of that.

What could cause it to kind of be pulled forward or push back and how that really portends into the trend of CapEx for the year? Is that should be -- we should expect to be front half weighted, but is that more Q1 and just kind of how to think about the timing of all this?

The fifth rig we're looking at letting go plus or minus midyear at this point. So I don't think you'll see a lot of impact to 2025 production associated with that rig getting laid down. What could change the timing on that rig, well productivity. 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 would 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 and minimize downtime. So that's a lever a lot of people don't think about relative to the capital program and maintaining maintenance levels of production that Danny referenced earlier. So that's the color that we can share with you at this time, Paul.

Noah Hungness, Bank of America.

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 lower GP&T costs?

Well, no, I'd say that we're always looking at opportunities to make sure that we're getting the best price and the best netback pricing. And so we've got contracts in place as those roll off, clearly, we're going to negotiate hard to get the best deal for ourselves. I'd say even before some of those contracts roll off, we have opportunities as we've grown and scale where we can -- there may be things that we can do that are win-wins for both the organizations that even while order 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.

Yes. No. I mean you kind of mentioned it. There is a lot of competition. There's pretty mature systems out there across water, gas, oil, kind of all the different pipeline pieces, which just creates competition, which is fantastic for us.

We've 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.

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 '25 corporate guidance from that non-op Marcellus position?

Yes, this is Danny again. So currently, we're thinking between 130 million and 140 million cubic feet coming through that -- coming through our non-op position there in Marcellus.

Is there -- just as a quick follow-up for clarification. Is there any seasonality in that production profile for the year?

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 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 goes -- 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.

David Deckelbaum, TD Cowen.

All I wanted to ask just a follow-up on the Marcellus. How do you think about that position, I guess, strategically now? And 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, then the position, you've been able to take advantage of attractive share buyback opportunities right now. And arguably, maybe that's in a sense that you're not getting credit for. Is that something that's under serious considerations as with the implement in the gas strip?

David, this is Danny. So I'll say that kind of -- as we said, we think that 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 a potential monetization there and then what we do with -- again, so any proceeds we would get out of that would be a capital allocation decision for ourselves at that moment.

I appreciate that. And then just curious as we think about capital efficiency improvements in '25 versus '24, I guess, that you guys highlighted. Are you -- is this -- are you more or less holding productivity flat and just assuming 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 in '24. But I guess like how do you think about just capturing efficiencies with longer laterals as it relates back to just cycle time improvements?

Well, the 3-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, towards 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 3-year time frame. So -- and I fully expect that we will see those because we've always seen them, and we've got a whole team that's focused really intently on that. And again, it also doesn't incorporate any significant uplift we would see in capital efficiency from a successful 4-mile program, which, as Darrin said, we've got our first one now drilled out to tow. So my expectation is as we see those efficiencies roll through, we'll see them roll through either through -- likely to lower CapEx spending for ourselves and incremental free cash flow from that lower CapEx level.

But again, we've put out both for '25 and for the 3-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 front of us, I feel pretty good about that.

Noel Parks, Tuohy Brothers Investment Research.

Just had couple of things. One thing just trying to really wrap my head around the whole notion of 4-mile laterals. As far as you know at this point, are there any new or expected frac protection issues introduced when you're doing 4-milers, I mean, I guess, specifically the like horseshoe shape? Or is it really just essentially the same as a pad with multiple 2-milers.

Yes. So no really incremental frac protect issues that we can think of. And the 4-miles we're looking at doing now are really straight 4-milers. And so -- which we think is the most efficient way to do things. We do look at alternate well shapes if we can't go too 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 4-miles, that's really what we're doing right now is straight 4-miles and no difference in frac protect concerns relative to what you would see if you were doing 2, 2-miles.

Great. And one thing, just looking at the reserves. Was there Enerplus from the Enerplus locations, any reduction in industry -- I'm sorry, inventory that pushed out in the 5-year CapEx rule? And just curious if as far as Enerplus, everything you're really planning to do as far as high grading is essentially done at this point with the integration.

Yes. So we -- as we brought the Enerplus reserves over into our system, clearly, we had the following U.S. SEC rules as opposed to Canadian rules that Enerplus followed. So that rolls through. We also like to -- we generally take a bit of conservative stance on our PUD bookings.

And so we're not fully booked out to the 5 years, and that's been a long-standing practice of the organization. And so yes, so -- and that -- so the reserves we've released incorporate both those effects.

(Operator Instructions) There are no further questions at this time. I will now turn the call over to Danny Brown with closing remarks.

All right. 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 substantial yet low decline and 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.

And with that, I appreciate everyone's interest, and thanks for joining our call.

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