Chord Energy - Earnings Call - Q4 2024

Executive Summary

• 4Q24 delivered solid operations and cash generation: oil volumes were above midpoint (153.3 MBopd), total volumes exceeded the high end (273.5 MBoepd), LOE came in below midpoint ($9.60/boe), and Adjusted FCF was $276.9MM as cost control and stronger NGL/gas realizations helped offset lower oil prices.
• Capital returns accelerated: Chord returned 100% of 4Q24 Adjusted FCF with $205MM in buybacks (repurchased 1.60MM shares at $127.82) and raised the base dividend 4% to $1.30 per share; since the Enerplus close, >5% of shares have been repurchased through Feb 21, 2025.
• 2025 outlook reaffirmed: midpoint CapEx of ~$1.4B to deliver ~152.5 MBopd oil, with ~$2.5B Adjusted EBITDA and ~$860MM Adjusted FCF at $70 WTI/$3.50 HH; 1Q25 volumes tempered to 149.5–152.5 MBopd due to severe winter weather, with sequential growth into 2Q/3Q.
• Operational catalysts: continued shift to longer laterals (40% 3-mile TILs planned in 2025; first 4-mile drilled and frac’d successfully), ongoing synergy capture, and efficiency improvements (simul-frac, faster cycle times) underpin capital efficiency and per-share growth focus via buybacks.
• Estimate context: Wall Street consensus from S&P Global was unavailable due to API limits at run-time; results vs estimates are not shown. Values would normally be anchored to S&P Global consensus.

What Went Well and What Went Wrong

What Went Well

• Volumes and cash margins: Oil volumes beat midpoint; total volumes topped guidance; LOE/boe below midpoint, driving $276.9MM Adjusted FCF (ex-reimbursed CapEx $282.1MM).
• Buyback-led capital returns: Returned 100% of Adjusted FCF in 4Q, with $205MM buybacks after the increased base dividend; >5% of shares repurchased since Enerplus close.
• Strategic execution and capital efficiency: CEO highlighted “significant synergy capture,” longer laterals, and conservative spacing that have lowered breakevens and extended inventory life. “We expect share repurchases to comprise a significant portion of future shareholder returns”.
• Management quote: “Fourth quarter performance was the latest in a series of strong quarters… robust shareholder returns… base dividend increased by 4% to $1.30 per share”.

What Went Wrong

• Oil price headwind QoQ: Oil price realized fell to $68.79/bbl from $73.51/bbl in 3Q, pressuring revenue despite strong volumes.
• Elevated G&A/merger costs: GAAP G&A was $45.7MM in 4Q (includes $9.0MM merger costs), though Cash G&A was $31.2MM with further synergy tailwinds expected in 2025.
• 1Q25 near‑term weather impact and differentials: Management cut 1Q25 oil volume outlook to 149.5–152.5 MBopd due to extreme cold; CFO flagged wider near‑term oil differentials that should improve gradually through 2025.

Transcript

Operator (participant)

Good morning, ladies and gentlemen, and welcome to the Chord Energy 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, please press star zero for the operator. 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 (VP of Investor Relations)

Thanks, Andrew. Good morning, everyone. This is Bob Bakanauskas, and today we're reporting fourth quarter 2024 financial and operational results. We are delighted to have you on the call. I am joined today by Danny Brown, our CEO, Michael Lou, our Chief Strategy and Commercial Officer, Darrin Henke, our COO, Richard Robuck, our CFO, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls.

Those risks include, among others, matters that we have described in our earnings releases as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference call, we will make reference to non-GAAP measures, and reconciliations to the applicable GAAP measures can be found in our earnings releases and on our website. We may also reference our current investor presentation, which you can find on our website. And with that, I'll turn the call over to our CEO, Danny Brown.

Danny Brown (CEO)

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. 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 four 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 break-evens 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 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, 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 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 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 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 mid-year. Additionally, we are currently running one full-time frac crew and one spot crew.

We expect to turn-in-line between 130-150 gross operated wells in 2025, including 22-32 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 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, with approximately 80% of that in the Williston, with a balance in Marcellus. The 2025 program is expected to deliver production similar to pro forma 2024, or between 152,000-153,000 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. In 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, 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.

Darrin Henke (COO)

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, are likely to implement many more in 2026 and beyond. As a reminder, our initial approach to four-mile wells will be converting two two-mile DSUs to one four-mile DSU. However, similar to Chord's evolution on the three-mile program, as we make progress on execution and drive the risk-adjusted returns higher, we 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 core 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 offsets the lower EUR per foot. Said 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 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 costs 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, 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 break-even 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 crew is 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 our delivery. I'll now turn it over to Richard.

Richard Robuck (CFO)

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'll 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 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 cost. 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%-10% of EBITDA, and first quarter cash taxes to approximate 1%-7% of EBITDA, each at oil prices of $60-$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 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 31st, 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 0.3 times 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 24th 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've put the organization in to succeed going forward. So with that, I'll hand the call over to Andrew for questions.

Operator (participant)

Thank you. Ladies and gentlemen, we'll now begin the question and answer session. 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 handset 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 (Managing Director of Energy Research)

Yeah. Hey, thanks, all. Can you give just some context around your outlook for capital in 2025 and maybe even going forward? I mean, obviously, you have a low and a 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 increasing just to simul frac or just more experience with that? And what is the potential to see downside pressure on that $1.4 billion kind of three-year outlook?

Danny Brown (CEO)

Hey, 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 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 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. 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 the 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 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 timeframe 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 four-mile laterals may come into the program, 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 going to put something out there that we didn't have high confidence we could meet or exceed, and I still feel the same way.

Scott Hanold (Managing Director of Energy Research)

Okay. I appreciate that. And part of that too, and I hate to try to layer another question there, 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?

Danny Brown (CEO)

I mentioned we've got one partial crew and one full crew. We're doing simul fracs with the full crew. We're not necessarily doing simul fracs with that partial crew. So for that full crew, that is all assuming simul frac, 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 (Managing Director of Energy Research)

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 and all buybacks. Look, your stock's up today, but it's still quite a bit under where you did your buybacks in 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 (CEO)

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.

Scott Hanold (Managing Director of Energy Research)

Thank you.

Danny Brown (CEO)

Your next question is from Derrick Whitfield from Texas Capital. Please go ahead.

Derrick Whitfield (Managing Director)

Good morning, all, and thanks for taking my questions.

Danny Brown (CEO)

Thanks, Derek.

Derrick Whitfield (Managing Director)

Regarding three-mile laterals, I want to thank you for your disclosures on slides nine and 10, 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 in that analysis. Maybe setting aside cost for a moment, where are you seeing the CUM 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 (CEO)

I'll start with the latter first. We absolutely are doing these things faster. I think with 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 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 after about six months, we start to see that converge pretty well. We're getting to sort of to the 95% on an equivalent basis on a per foot EUR recovery after around six months, and you're essentially all the way there within a one-year timeframe.

So that first three or four months is really where you see the difference in the CUM EURs, and so if you're focusing on that very early well time 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 (Managing Director)

Terrific. And then regarding your first four-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 three-mile to four-mile laterals after accounting for the cycle times?

Danny Brown (CEO)

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 (COO)

Yeah, Derrick, knock on wood, boy, the first four-mile well has really gone off without a hitch. Spud to rig release was 14 and a half days, the fastest well spudded in the basin at 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 going through all that pipe with the friction losses, but all that went really well. And 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 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 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 (Managing Director)

Great update. Thanks for your time.

Darrin Henke (COO)

Yes, sir.

Operator (participant)

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

Neal Dingmann (Managing Director of Energy Research)

Good morning. Thanks for the time, guys. Danny, 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 see the improvement now 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 efficiency gains will be coming from?

Danny Brown (CEO)

So Neal, appreciate the question. Again, with incremental reps, you just get better. And so we're starting to get some reps under our belt from a three-mile perspective. And so we've seen that happen. Certainly, we saw a dramatic improvement last year from an efficiency perspective as we moved to adopt simul frac across the fleet. And 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'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 surpass our original expectations going in. At least that's been my history with this industry and with this organization. So I think, again, you'll see sort of 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. But if we're able to see 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 (Managing Director of Energy Research)

I like that upside, and then just a question on M&A. Have a sense of it, I think you all 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?

Danny Brown (CEO)

To your point, Neal, I think 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 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 full cycle value.

Neal Dingmann (Managing Director of Energy Research)

That makes sense. Thank you so much.

Danny Brown (CEO)

Thanks, Neil.

Operator (participant)

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

Oliver Huang (Director of E&P Research)

Good morning, all, and thanks for taking the questions. 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 $3.50 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?

Darrin Henke (COO)

Yeah, 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 what's happening with NGL prices at the same time because you've seen that impact as well because we're allocating it to both gas and NGL. But you're definitely right. As gas prices go up, we will be scaling incrementally to capture that value.

Oliver Huang (Director of E&P Research)

Okay. Makes sense. And maybe just on the non-ops 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'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 (Chief Strategy and Commercial Officer)

Hey, Oliver, this is Michael. Good question on the non-ops 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 returns on both the operated 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 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 (Director of E&P Research)

Makes sense. Thanks for the time.

Danny Brown (CEO)

Thank you. Thanks, Oliver.

Operator (participant)

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

John Abbott (VP of E&P Research)

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 (CEO)

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 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 you probably see a small incremental pull from 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 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, and 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 (VP of E&P Research)

Appreciate it. And then for our 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?

Danny Brown (CEO)

We think we have been the beneficiary in both Williston and for the non-op production we have 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 do we maximize value delivery to shareholders from that asset over time.

John Abbott (VP of E&P Research)

Thank you very much for taking our questions.

Danny Brown (CEO)

Thanks, John.

Operator (participant)

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

Josh Silverstein (Managing Director and Head of Energy Research)

Hey, thanks. Good morning, guys. Just wanted to follow up on the 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? I'm just curious given the valuation of the stock. Thanks.

Danny Brown (CEO)

Yeah, appreciate it, Josh. As I said, it's really a capital allocation decision for us. And so you can see 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. Ultimately, we've got a way of increasing leverage relative to capital investment opportunities, etc., 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 (Managing Director and Head of Energy Research)

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 three miles? How many wells in the Middle Bakken? Is there anything left in the Three Forks? Just to kind of give them more color around that. Thanks.

Danny Brown (CEO)

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 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 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.

Josh Silverstein (Managing Director and Head of Energy Research)

Thanks.

Operator (participant)

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

Paul Diamond (Equity Research Analyst)

Thank you. Good morning, Oliver, for taking the call. So you talked about the conversion and general conversion of two-mile DSUs 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. Just wanted to see if you could kind of dial in how much of that 60% is potentially convertible. Is it all? It just matters on the economics of the well or just kind of how to think about that.

Danny Brown (CEO)

Yeah, I'd say, generally speaking, Paul, we think we've got sort of, I'd call it greater than 50% from a three-mile inventory perspective currently. And so then there's a balance that is two-mile inventory. We've got some that are 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 up to around 80% into that three-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 landlocked. It may be somewhat difficult to do that.

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 respace some of these three miles to four miles to see the upside?" So 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, replatting out the whole basin, not a trivial thing to do, and we need to see some results first.

Paul Diamond (Equity Research Analyst)

Understood. Appreciate the clarity. Just a quick follow-up. You all talked about dropping a rate mid-year. You talked about just the timing of that. What could cause it to kind of be pulled forward or pushed back and how that really portends into the trend of CapEx for the year? I know 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?

Darrin Henke (COO)

Yeah, the fifth rig we're looking at letting go plus or minus mid-year 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? Just well productivity. If we see better improvements in runtime 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. While our production team is focused on that every day, we're working to improve our runtimes and minimize downtime. So it'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.

Paul Diamond (Equity Research Analyst)

Understood. Appreciate the clarity. I'll leave it there.

Danny Brown (CEO)

Your next question is from Noah Hungness from Bank of America. Please go ahead.

Noah Hungness (Equity Research Analyst)

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 lower GP&T costs?

Danny Brown (CEO)

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've got contracts in place as those roll off. Clearly, we're going to negotiate hard to get the best deal for ourselves. And I'd say even before some of those contracts roll off, we have opportunities as we've grown in scale where we can there may be things that we can do that are win-wins for both organizations that even while we're under contract, it 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 (Chief Strategy and Commercial Officer)

Yeah, 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 that 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.

Noah Hungness (Equity Research Analyst)

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 (CEO)

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

Noah Hungness (Equity Research Analyst)

Just as a quick follow-up or clarification, is there any seasonality in that production profile through the year?

Danny Brown (CEO)

In general, that'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, 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 (Equity Research Analyst)

Sounds good. Thanks for taking our questions.

Michael Lou (Chief Strategy and Commercial Officer)

Thank you. Thanks, Noah.

Operator (participant)

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 (Managing Director of Sustainability and Energy Transition)

Thanks for getting me on, guys. And good morning to you all. I wanted to ask just to 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 the non-op position? 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 (CEO)

Hey, David, this is Danny. So I'll say that kind of as we said, we think that'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 that, again, so any proceeds we would get out of that would be a capital allocation decision for ourselves at that moment.

David Deckelbaum (Managing Director of Sustainability and Energy Transition)

I appreciate that. And then just curious, just as we think about capital efficiency improvements in 2025 versus 2024, I guess, that you guys highlighted, 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 2024, but I guess how do you think about just capturing efficiencies with longer laterals as it relates back to just cycle time improvements?

Danny Brown (CEO)

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. 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 four-mile program, which, as Darrin said, we've got our first one now drilled out to toe.

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. 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. I feel, because we've got these efficiencies still in front of us, I feel pretty good about that.

David Deckelbaum (Managing Director of Sustainability and Energy Transition)

Thanks, Danny. Appreciate it.

Danny Brown (CEO)

Thanks, David.

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

Noel Parks (Managing Director of CleanTech and E&P)

Hi, good morning. Just had a couple of things. 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 if you're in a horseshoe shape, or is it really just essentially the same as a pad with multiple two-milers?

Danny Brown (CEO)

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 which we think is the most efficient way to do things. We do look at alternate well shapes. If we can't go to 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 is straight four miles and no difference in frac protect concerns relative to what you would see if you were doing two two-miles.

Noel Parks (Managing Director of CleanTech and E&P)

Great. Thanks a lot. And one thing, just looking at the reserves, was there from the Enerplus locations, any reduction in industry sorry, in inventory that got pushed out in the five-year CapEx rule? And I'm 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 integration.

Danny Brown (CEO)

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

Noel Parks (Managing Director of CleanTech and E&P)

Great. Thanks a lot.

Danny Brown (CEO)

Fantastic. Thanks, Noel.

Operator (participant)

Ladies and gentlemen, as a reminder, should you have any questions, please press the star key followed by the number one. We'll 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 (CEO)

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.

Operator (participant)

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