Chord Energy Corporation (NASDAQ:CHRD) Q3 2024 Earnings Call Transcript

Chord Energy Corporation (NASDAQ:CHRD) Q3 2024 Earnings Call Transcript November 7, 2024

Operator: Good morning, ladies and gentlemen, and welcome to the Chord Energy Third Quarter 2024 Earnings Call. [Operator Instructions]. This call is being recorded on Thursday, November 07, 2024. I would now like to turn the conference over to Bob Bakanauskas, Vice President Investor Relations. Please go ahead.

Bob Bakanauskas: Thank you, Dion, and good morning, everyone. This is Bob Bakanauskas. Today, we’re reporting our third quarter 2024 financial and operational results. We are delighted to have you on the call. I’m joined today by Danny Brown, our CEO; Michael Lou, our Chief Strategy and Commercial Officer; Darren Henke, our COO; and Richard Robuck our CFO, and 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 release and conference calls.

Those risks include, among others, matters that we have described in our earnings release 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 call, we will make reference to non-GAAP measures and reconciliations to the applicable GAAP measures can be found in our earnings release and on our website. We may also reference our current investor presentation, which you can find on our website. And with that, I’ll turn the call over to our CEO, Danny Brown.

Danny Brown: Thanks, Bob. Good morning, everyone, and thanks for joining our call. Over the next few minutes, I plan to provide a brief overview of Chord’s third quarter performance and resulting return of capital before turning the discussion to our 3-year outlook, which Chord released last night. From there, I’ll turn it to Darrin who will comment on our operations, including capital efficiency improvements, which support what we think is a compelling outlook. Darrin will then pass it to Richard for more details on our financial results before we open it up to Q&A. But before that, I wanted to take a few quick moments and make some comments on recent events in North Dakota. In early October, several wildfires spread in the northwest portion of the state, which tragically led to two fatalities as well as damage to property and equipment.

We are very thankful that the Chord team is safe. However, our thoughts and prayers are with the affected communities and citizens as they rebuild. Chord is also grateful for the leadership shown by both the state and MHA Nation during the fires and for the efforts of our field personnel, which proactively shut in various sites and facilities and coordinated with local authorities. The curtailments to our production were short-lived, and we expect the impact of fourth quarter oil volumes to be about 900 barrels of oil per day, which is reflected in our guidance. Turning to third quarter results. Chord delivered another great quarter with solid operating results, yielding free cash flow above expectations, which supported robust shareholder returns.

Specifically, third quarter oil volumes were toward the top end of guidance, driven by strong execution, well performance and lower downtime. Capital was below expectations, reflecting operational efficiencies, lower-than-expected cost as well as timing adjustments to the program. Operating expenses also came in below expectations as the team continues to improve operating margins. My thanks to our field, development and execution teams for delivering favorable results really across the board, fantastic job by all. This strong performance led to adjusted free cash flow for the quarter of approximately $312 million, and Chord will be returning 75% of this amount to shareholders. Given our base dividend of $1.25 per share and our normal course of share repurchases in the quarter of $146 million, declared a variable dividend of $0.19 per share.

After the base dividend, share repurchases represented 93% of capital return for the quarter, and we bought back over 1.5% of shares outstanding. Given the compelling valuation we see at our current share price, we expect to continue to lean into buybacks in this environment. Additionally, Chord announced the divestiture of the DJ Basin assets acquired via the Enerplus transaction and expects to use net proceeds to fund acquisition opportunities as well as repurchase shares. We would expect any repurchases related to the DJ sale to be incremental to the normal course return of capital program. Additionally, last night, we issued fourth quarter and updated full year guidance. Net of the divestiture, we increased full year pro forma oil guidance for the second time this year, despite the impact from the fires, mostly reflecting outperformance in the third quarter.

We also trimmed full year capital guidance reflecting improved program efficiencies. We are also trending well on operating expenses and are pleased with the progress we’re seeing over the last year or so on this front. Finally, we lowered gas volumes to reflect our latest estimates for our non-operated Marcellus production. Turning to our 3-year plan. The Chord team has been working diligently to integrate the Enerplus assets, drive synergy capture and enhance our capital efficiency. We are now far enough along with the integration that we feel confident providing a medium-term outlook for our organization, namely holding oil volumes steady at 152,000 to 153,000 barrels per day from 2025 through 2027 with annual capital expenditures of $1.4 billion per year.

Our plan reflects the value the team has created through their focus on strong operational performance, continuous improvement, capturing over $200 million of synergies annually and represents the quality and depth of our inventory. Importantly, this is our current look, and we see further upside to these plans as we work to continue to extend lateral lengths, including incorporating 4-mile wells and push continuous improvement and cost reduction across all aspects of our business. Our strategic actions, coupled with our fantastic operations team, have created what we believe is a valuable and increasingly rare asset. Chord has a substantial yet low decline 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 underlying assumptions and operational performance to deliver our plans. As a reminder, in our presentation, we’ve included some material focused on helping investors better understand how attractive the Williston Basin is from an investment standpoint. We’ve added a graph contrasting the major Lower 48 basins in terms of average cumulative oil recovery per well versus time. This is admittedly simplistic as it ignores other factors such as well cost, but it does highlight how productive Williston wells are versus other basins. We think there is a bit of a misconception out there that the Bakken’s cost of supply is materially higher than that of other basins. But if you look at the well data and basin-specific productivity measures, you can clearly see the Williston Basin competes quite favorably with other oily basins.

While our team and assets delivered another oil beat in the third quarter, we have had queries recently from folks trying to better understand early production data that may have led to concerns about us meeting our production guidance. I wanted to use this call as an opportunity to help investors understand trends seen in the state-reported data. First, early time production is inherently volatile and impacted by a myriad of factors. These may include midstream issues, large disposal constraints, downtime related to artificial lift installation, testing or a host of other factors that have nothing to do with the wells’ inherent productive capacity and expected ultimate recovery. Second, there’s also a variability across the basin on flow back methodology.

In some instances, wells are brought online at high IPs and sharper declines. While other instances, you see wells brought online more gradually, resulting in less early time production but improved longer-term performance. As a reminder, Chord has shifted to drilling more widely spaced and longer laterals on average than others in the basin. While we don’t initially flow these wells back as hard as some other operators, we believe our wells benefit from lower declines and higher ultimate recovery over time. This is demonstrated on Slide 8, which shows that Chord’s 12-month oil teams [ph] are among the best in the basin, while our 3-month teams are more average performers. Note as well that as we move to longer laterals, we are not moving our initial production rates up and lockstep with the increased lateral length.

So as the average lateral length of the program increases, when looking at perfect productivity, production will be divided by a greater denominator and will show lower early time well productivity. This analysis misses two things: One, we see per foot recovery catching up over time due to the lower decline; and two, well costs for the longer laterals are dramatically lower, meaning the resulting returns are significantly higher as we move to 3-mile wells. Slide 8 adjusts for these factors and shows Chord’s lateral length adjusted average 2023 and 2024 well productivity relative to drilling and completions cost. By dividing well productivity per foot by drilling and completions cost per foot, it gives a sense as to the overall capital efficiency of the program.

As you can see, 2024 program starts off a little below 2023, but quickly catches up and ultimately surpasses last year due to a higher concentration of 3-mile wells. To sum it up, the longer lateral program is working and delivering greatly improved capital efficiency and returns. We encourage investors to observe our long-term well data in light of our wider spacing, conservative flowback strategy, inherent variability in near-term data and the nature of longer laterals. And finally, before I turn it over to Darrin, I want to say that we are committed to delivering affordable and reliable energy and to do so in a sustainable and responsible manner. In the spirit of transparency with our stakeholders, we recently published Chord’s 2023 sustainability report.

Thank you to the team for putting this together as it does a great job discussing our business and highlighting our efforts on emissions reductions, workforce, health and safety, corporate governance, philanthropy and other topics. We welcome feedback from our stakeholders on our progress and look forward to building upon our ESG efforts to shape an ever stronger future for Chord and the communities we serve. To summarize, I couldn’t be more pleased with the state of the business, and we are in a fabulous position to generate substantial value in the coming years. With that, I’ll turn it to Darrin.

Darrin Henke: Thanks, Danny. Operationally, it was a strong quarter as the team continues to deliver. I want to take a few minutes and discuss the strength of our asset base and all the factors giving Chord operational momentum into 2025 and beyond. I’ve been at Chord almost a year now and have been impressed with the culture of continuous improvement as the team constantly challenges themselves to drive efficiencies through leveraging technology and innovation. Chord remains an industry leader in executing longer laterals and the results have been impressive. We’ve turned in line over 100 3-mile lateral wells in the past few years, while D&C cycle times and cleanouts continue to improve. This quarter, we formally updated our third mile productivity assumption to be essentially identical to the first 2 miles.

Slide 7 of our investor presentation highlights over 60, 3-mile wells with sufficient production history to illustrate the recovery is higher than our original type curves, yielding increased ultimate recoveries and better capital efficiency. One of the largest technical accomplishments involves cleaning out the third mile where the Chord team has routinely been successful drilling out the frac plugs and reaching TD on most wells. Pro forma, Chord’s inventory consists of approximately 40% longer laterals, and we believe we can increase that percentage materially over the next few years. Just a quick update on 4-mile lateral wells. Chord recently spud its first 4-mile lateral and plans several more in 2025. We expect to have results from our first 4-mile well by the second half of next year and are likely to implement more 4-mile wells in 2026.

Turning to well spacing. It’s important to consider Chord’s average spacing across the basin is wider than other operators. This conservative spacing has helped keep declines shallow, production flat and reinvestment rates low. Slide 8 highlights Chord’s decline rate relative to our peers, which compares quite favorably. This advantage is driven not only by wider spacing but longer laterals tend to have shallower initial declines as well. Wider spacing has been a key driver to improve Chord’s capital efficiency in recent years as it has delivered similar DSU recoveries with substantially less wells and capital. Relative to integration, we remain extremely confident in the strategic and financial benefits of the Enerplus transaction. Our combined team has done a remarkable job integrating the assets, people, processes and systems, all the while delivering an outstanding operational quarter.

Danny outlined our 3-year plan where performance improvement is driven by operational advancements and synergy capture. Board expects to enhance returns on legacy Enerplus assets by applying techniques it has developed over the past several years, including longer laterals, optimized spacing and reduced downtime. In addition to our asset management approach, we continue to drive cycle times lower for both drilling and completion operations. On the drilling side, we are in the process of upgrading the legacy Enerplus rigs to Chord specs, and we continue to set new records with 6 of our 8 fastest wells being drilled in the third quarter. To put this in perspective, we are drilling over 30% more feet per day than we were just one year ago. On the completion side, we are implementing some frac operations on pad, which has driven down nonproductive time, leading to well cost savings and getting production on quicker.

Simul-frac has resulted in a 40% increase in fracked feet per day. Our operations team has driven costs down across the entire wellbore, including profit costs by utilizing 100% local sand. Downtime continues to improve, especially as we adopt Chord’s best practices across our entire asset while also driving continuous improvement. To sum it up, Chord has an impressive track record of consistent execution and strong returns. We look forward to delivering on our long-term outlook. I’ll now turn it over to Richard.

Richard Robuck: Thanks, Darrin. I’ll focus my comments on the third quarter results and then discuss updates to our guidance. In the third quarter, Chord generated adjusted free cash flow of $312 million with strong volumes, lower capital and good cost control contributing to the upside. Oil volumes were towards the top end of guidance, while total volumes were above the top end. Oil realizations in the third quarter averaged about $1.50 below WTI. NGL realizations as a percent of WTI were at the low end of the guidance range of 8% and natural gas realizations were below the low end of the range at 20% of Henry Hub. Henry Hub averaged $2.16 per MMBtu, which was weaker than our outlook, which was set at strip at the time we released earnings last time.

Realized gas prices in the Bakken were negatively impacted by depressed pricing at AECO, which is the gas hub in which our gas prices are mostly correlated. AECO started dislocating from its historical discount to Henry Hub around the second quarter and that dislocation continued into the third quarter. Additionally, 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, like the most recent quarters we’ve experienced. With gas prices trading at low levels, the fees deducted from our price results in lower realization as a percent of benchmark price. Turning to operating costs. LOE was below expectation at $9.56 per BOE, reflecting better downtime and lower workover costs.

Cash GPT was $2.91 per BOE. Cash G&A was $27.9 million, excluding merger-related costs of $17.5 million. Production taxes averaged 9% of commodity sales in the third quarter, reflecting higher oil contribution in our revenue mix. Cash taxes of $13 million was below our expectations. CapEx of $329 million was below the low end of our guidance, reflecting program efficiencies and minor shifts in program timing. As of September 30, Chord had $470 million drawn on its $3 billion credit facility, which has $1.5 billion of elected commitments. Liquidity as of September 30 was $1.1 billion, including $52 million of cash and approximately $1 billion of availability under our credit facility, net of letters of credit. Net leverage was 0.3 times at September 30.

During the third quarter, Chord repaid $63 million of Enerplus senior notes and net debt decreased by $20 million, even as we paid out our second quarter dividends of approximately $156 million and bought back 146 million of shares during the quarter. As we look forward now, on a pro forma basis, Chord increased its oil guide by about 600 barrels a day, which marks the second consecutive volume guidance increase this year. The midpoint of our fourth quarter oil guide of 152,000 barrels of oil per day would have been approximately 153,000 barrels of oil per day adjusting for the impacts of the DJ divestiture and the shut-ins related to the wildfires. Oil differentials are improving in the Williston Basin to the best levels we’ve seen all year, so we’re capturing that in our fourth quarter guide.

Our marketing team continues to deliver basin-leading oil differentials. NGL realizations are expected to be similar to the third quarter. And as I discussed earlier, natural gas realizations have been weaker due to AECO pricing. The recent improvement in AECO pricing is reflected in our realized natural gas pricing guidance. Looking at and further in time, realizations should also improve quickly in environments where gas prices rise. On the cost side of the business, we are expecting basically flat LOE and GPT quarter-over-quarter. Our G&A guidance remains unchanged, and it does not include the impact of merger-related items, which are continuing to step down each quarter. Cash taxes are expected to be 0% to 5% of adjusted EBITDA in the fourth quarter at prices ranging between $60 and $80 per barrel WTI, which is down from our original expectations.

Our preliminary 2025 expectations reflect cash taxes of 2% to 11% at prices of $60 to $80 per barrel WTI. With the team continuing to get more efficient, we lowered our pro forma full year capital spending guidance by $10 million. Separately, Chord layered on some hedges during the quarter and since our last update. So our derivatives position as of November 5 can be found in our latest investor presentation. In closing, the team’s hard work on integrating Enerplus asset, while at the same time, improving day-to-day operations gives me great conviction in our ability to deliver our 3-year plan that we just rolled out. I have great confidence in the team as the technical and operational leader in the Williston Basin. You all delivered another great quarter and have positioned us in an enviable place to continue to add value for our shareholders in the future.

With that, I’ll hand the call over to Dion to open up the line for questions.

Q&A Session

Operator: [Operator Instructions] Your first question comes from Neal Dingmann of Truist Securities. Please go ahead.

Neal Dingmann: Good morning guys. Nice quarter. My first question is around that like that 3-year plan of yours. I’m just wondering, are there various commodity price scenarios where you would alter the suggested spend. And then I’m wondering if you continue to see further operational efficiencies, Danny, as you and the group have, would that cause you to increase activity? Or would you maintain activity and just you’d see the free cash flow boost?

Danny Brown: Yes. So thanks for the question, Neal. On the latter part of your question with respect to sort of what we’re gearing this around, it would really be around if we saw increased efficiencies, which candidly, we’ve seen the teams have been delivering increased efficiencies really quarter-on-quarter. And so I don’t think we’re at the end of that. The train had reached the station on that. I expect we will continue to see increased efficiencies relative to what we put in this plan. And as if and when we do see that, we’re going to not increase activity. We won’t be managing to sort of holding our capital level flat and let production float up. We’re likely to do the exact opposite, just kind of maintain a flattish production profile. And if we see — if we need to spend less capital to do so, fantastic, and we’ll just let some more free cash flow through the system.

Neal Dingmann: I was hoping you’d say that then — go ahead, guys. Were you going to say something…

Danny Brown: No, what was your first question again, Neal?

Neal Dingmann: Was more just on the price sensitivities, again, if we had a 60 versus 80, just how stable that plan would be?

Danny Brown: Yes, I’d say the plan is really sort of gear around our, I’d say, current commodity price environment. Obviously, we are going to be observing what the market is telling us. This is all just a capital allocation decision at the end of the day. We think we’ve got great inventory. We’ve got great sort of a great asset. But if the market is telling us something vastly different from where we’re at right now, then we’re going to respond — we’ll respond accordingly and allocate capital accordingly. So if we saw dramatically lower commodity prices, we would have to thank what’s the market telling us. And should we continue to execute the plan as contemplated? Or do we have better capital allocation opportunities? Simultaneously, if we saw prices spike telling us the market was undersupplied and we weighed this relative to our other capital allocation opportunities, we might choose to do something a little different.

But — so I’ll call it around a band of where we’re at today, we think this plan is a solid one, very, very achievable, maybe somewhat conservative, and we expect to be able to deliver upon it or do a little better.

Neal Dingmann: Great. And then second question, maybe just around now you’ve got such a large 1.3 million acre position. I’m just wondering how you maybe see the variability around this. Specifically, given the improved completions that you’re seeing now really throughout much of the portfolio, I’m just wondering how do you see well breakeven? I don’t know, like, if you look in the West in Williams, McKenzie counties versus going East around Montreal how different do breakevens now suggest?

Danny Brown: The interesting thing about it, Neal, is as we look at our acreage out more toward the West relative to what I’m going to call sort of the historic core of the basin, in the historic core of the basin where just due to the legacy development plan, we’re probably more 2-mile lateral development there. And so if you look at the 3-mile laterals, we can do out further in the West where we don’t have as much legacy development, and we’re able to put the units together a little bit more differently. We see sort of really similar returns and investment opportunity between the two. And so that’s a really neat thing about what we’ve been able to do as we moved over to a little bit wider spacing and longer laterals out in the Western portion of the acreage as is you’re able to deliver returns that are pretty similar to the Chord.

Now the underlying geology in the Chord continues to be better. And so for sort of same, same, the Chord is the Chord, but we’ve been able to generate economic returns that are similar to the Chord moving out West by drilling longer in space and a little wider.

Neal Dingmann: Great. Thank you, Dan.

Danny Brown: Thank you.

Operator: Your next question comes from Scott Hanold of RBC. Please go ahead.

Scott Hanold: Yes, thanks. So I was wondering if you could provide some color on those updated 3-mile EURs. What are you seeing in the progression of performance over time that gave you confidence in now expecting similar EURs per foot? Just talk through like some of the challenges or physical challenges that you have overcome as you obviously get out closer to the toe?

Danny Brown: Yes. Thanks, Scott. So I’m going to start off with this and then turn it over to Darrin for some color commentary at the end. But I think really, Darrin mentioned in his prepared remarks, the getting out sort of to the full lateral length. And so cleaning out all the way to the toe has been a big thing for us, which the team has done a great job. And I guess for the first part of your question around what we’ve seen, it gives us confidence to do — to sort of move up from this 80% scaling factor for the third mile to 100% scaling factor is, it’s really just data. And so we needed to see well performance over time. We had hopes that we would be able to move this up from 80% of the third mile to 100% of the third mile that needed to see the data and see how the wells actually performed.

And so now that we’ve got that data, we are very confident on how we look here and I’ve been really, really pleased with what we’re seeing from that third mile. So I’ll turn it over to Darrin for incremental comments.

Darrin Henke: Yes, Scott, it was really late summer of 2023 in the third quarter that we started getting cleaned out all the way to TD. And so when a person looks at those wells that we brought online really in the last 12 months or so, you can — you see the benefits of that and the production, as our engineers forecast the reserves, look spot on to be 150% of a 2-mile well for our 3-mile wells. So same recovery on a per foot basis.

Scott Hanold: Okay, thanks for that. And my follow-up is on the, I guess, 3-year outlook, a couple of questions just to clarify. As you look at that, there’s two things that stand out to me. Number one, Dan, you kind of mentioned the $1.4 billion is kind of based on what you know today. Can you give us some context of like is that contemplating all the full synergies? Or what is the benefit of getting the full synergies? Like where could that go? And number two, as you look at the mix of your properties across the Bakken, like how do you think about the mix on a year-to-year basis as it progresses through it? Is it could be pretty ratable? Or is there going to be certain areas that get more focused in certain parts of the plan?

Danny Brown: Yes. So I think as we look at the overall development plan, we’re going to have — we’ve seen real benefit, I think, in having a little bit of a portfolio effect in how we deliver the plan. So we’ve got the rigs and delivery and completion a little bit spread out across the field. We’ll have — and so I think we’ll continue — really the underlying plan contemplates that as we move forward. And so I think in early time, we tilt in slightly to the legacy Enerplus acreage, not dramatically, but tilt in slightly to the Enerplus acreage as you would anticipate, given that position, but it’s really a pretty spread out plan over this 3-year time frame. With respect to opportunities to improve the plan, I’d say clearly, service cost will follow activity, which will follow oil price.

And so we’ll see where overall pricing goes, which is going to set activity levels, which — and service cost will be pinned off of that. And so I can’t answer that question. what we’ve got contemplated in the plan currently is essentially what we’re seeing currently in the latter half of 2024, and that’s the well cost we have assumed in the plans as we move forward. So as we could see service costs come down, that would flow through. If we see service costs move up, that could put upward pressure on us. However, I would say that what we’ve seen the teams do is get more and more efficient quarter on quarter-on-quarter. And I think we’ve got a slide in the deck showing some of the improvements in D&C costs we’ve seen over the past year. Again, I don’t see that slowing down anytime soon.

And so I think we’re going to have some natural efficiencies that roll through the system. Last thing I’ll mention is — last thing I’ll mention, Scott, is that this doesn’t contemplate really any benefit from 4-mile wells. And so we’re drilling 1 of those. We’ve spud 1 now. We’ll see results. I personally have high hopes and expectations around 4 miles, but that’s not contemplated in this plan at all. And so as we see success with 4-mile wells, potentially converting 2-mile wells over to 4-mile wells, that’s just upside that we would see here as well.

Scott Hanold: Yes. And just to clarify, the synergies, is that fully in the Enerplus, do you think you’re pretty much at the full synergy run rate that’s inferred into that?

Danny Brown: So the $200 million plus synergies, of course, only a portion of that is capital, but this does have the capital synergies we’re anticipating from the Enerplus plan baked into the system. What it doesn’t have baked in is sort of the continuous improvement, efficiency improvement because at some point, what’s the synergy and what’s just getting better. And what I know is we’re just getting better.

Scott Hanold: Got it. Thank you.

Danny Brown: Thanks, Scott.

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

Noah Hungness: Good morning, all. I was just hoping you guys could give us maybe some operational color around what you all were able to do with getting coiled tubing out to — up to TD on the extended laterals?

Darrin Henke: Yes. Noah, good question. The — it really comes down to the bottom hole assembly that we use in the fluid rates that we’re pumping and really a lot of technical details that probably aren’t appropriate for the call. But needless to say, our team is performing very admirably in this area relative to our peers. And someone might argue it’s a competitive advantage for Chord. So I’ll leave it at that.

Noah Hungness: Makes sense. And then you guys continue to mention that you’re looking to incorporate 3-mile laterals on legacy Enerplus acreage. Is that in the program for 2025? Or when should we start to think that those extended laterals on that acreage would be incorporated into the development plan?

Danny Brown: Yes. We’ve got — we are believers in 3-mile laterals, as I mentioned in my prepared remarks, that plan is working. We do have a portion of the Enerplus asset. However, that is really — it doesn’t really lend itself for 3-mile development because there’s existing development that would really preclude you from going out to the third mile. And you don’t have an opportunity really to stat to 2 miles together. It’s sort of a section of 2 miles that need to be developed 2 miles as we move forward. And so we’ll see some of that roll through the system. We won’t be able to transfer all of their wells over to 3 miles. And so you’ll see some of that in the 2025 plan. Although where we have opportunity to move to 3 miles, we’ll do that as well. So I’d say it’s going to be a mix, probably tilting more towards 2 miles just because of that legacy development program that surrounds it, but you’ll see some 3 miles, too.

Noah Hungness: Makes sense guys. Thanks.

Operator: Our next question comes from Phillips Johnston of Capital One. Please go ahead.

Phillips Johnston: Hey, thanks for the time. I appreciate the color on the 3-year outlook. Maybe just a follow-up on Scott’s question in terms of some of the assumptions there. Just from a modeling standpoint, can you maybe talk about what that assumes in terms of average gross wells per year or gross lateral feet per year however you guys think about it as well as kind of average working interest per year? And are you expecting any significant variability in either of those metrics in any given year?

Danny Brown: Thanks for the question, Phillips. I’m going to give you directional comments on this because we’ll come out with specific guidance as we come out in February. So really, the intent of the 3-year plan was to get directional guide here. So I’ll talk directionally about what we’re expecting as we move forward. We’re expecting to see, as we got the plan laid out currently, we’re going to see, I’d say, our operated well count decreased slightly as we move forward. That’s going to largely driven by increased lateral length. And so as we’re drilling out further, we don’t need as many wells to roll through the system in order to deliver the plan. And so you’ll see that creep down a little bit and then a slight increase in our non-op.

We just really brought a lot of non-op into the system with both the XTO acquisition and with Enerplus. These are wells in the core of the field. They are really compelling investment opportunities. And so we’ll be putting a little bit more into those as we move forward.

Phillips Johnston: All right. Sounds good. And I think you guys make a good point on these longer laterals having a positive impact here. Base PDP decline rate. And I like the chart on Page 8 that shows your decline rate versus peers. I guess regarding Chord’s 35% rate, how much lower do you think you can drive that by the end of this 3-year plan is with the higher mix of the 3-mile laterals?

Danny Brown: I don’t have a specific number for you, Phillips. I’d say I do expect it to have downward pressure on it, though, which will be beneficial for us, obviously, as we have — as the program is made up with a larger portion of 3-mile laterals, which have inherently shallower decline. And we sort of — we’ve got a little bit of certainly with the legacy Enerplus assets, that was a growing asset that we’re going to — going more from a maintenance standpoint as we move forward. So both of those things should be beneficial from a decline perspective.

Phillips Johnston: Thanks guys. Thanks, Danny.

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

Oliver Huang: Good morning all and thanks for taking the questions. As it relates to simul-frac, just any sort of color in terms of what percent of the program this could kind of migrate towards over the next 12 to 18 months? And are these savings already included in the latest set of D&C cost figures that you all provided last night?

Darrin Henke: Yes. So as we look forward, Oliver, the next year’s plan, we’re probably looking at roughly 1.5 frac crews and the 1 full-time dedicated frac crew, our plan is to do simul-fracs the entire year with that frac crew. So — and then the other crew will be more of a zipper frac crew the half a crew. And I will tell you, the feet per day that we’re getting fracked as we’ve switched to simul fracking, it just — the team is executing very, very well. And it’s really eye-opening to see the efficiencies that they’ve gained really in the last few months as we’ve expanded the simul-frac activity. So we could even have more downward pressure on the amount of frac — total frac activity that we’ll need relative to crews next year. That is in next year’s plan. Like Danny said, we’ll come out with more guidance next year directionally though it is in the 3-year plan.

Oliver Huang: That’s helpful. And maybe just another second question just on the returns. Just wanted to kind of get a better understanding around the moving pieces here. The shift definitely makes sense given move we’ve seen in the equity over the last few months. But with the increased preference to the buyback, is that going to be more viewed as something more programmatic of quarterly component now? Or is that something that’s going to be more opportunistic in nature within the quarter?

Danny Brown: Thanks for the question, Oliver. I’d say we’ve — share repurchases have always played a part of our program. And so as we look through this, we’ve been — really we’ve been repurchasing shares in all environments. And so I would say as we look at the landscape now, we think it’s a particularly compelling opportunity in the environment we’re in. But we’ve always — we’ve been doing share repurchases all along the way. And so I would say in the near term, certainly, we anticipate leaning very, very heavily into share repurchases. But I think share repurchases will always play a role within our overall framework.

Richard Robuck: Absolutely. I think the only thing that I would add is that with the Enerplus transaction, we just had times where we couldn’t be buying shares. And so it looked like we were landing into the variable, and that actually wasn’t the case. It was just that we were unable to be buying at those times. And I would — you look back to the month of June, once we closed the transaction, you saw us buy heavily. And so that represented the entire quarter. June representing the entire quarter of buybacks that we did.

Oliver Huang: Thanks for the time.

Richard Robuck: Thanks, Oliver.

Operator: Your next question comes from David Deckelbaum of TD Cowen. Please go ahead.

David Deckelbaum: Yes, thanks guys for the time this morning. I just wanted to confirm, as you think about the 2025 through 2027 plan, as you move into more of the Enerplus acreage, I guess, as think 2026, 2027, how do you think about — is the spacing going to be identical to the way that you’re spacing some of the legacy Chord wells in acreage now? Or is it going to be on tighter spacing just based on the development there?

Danny Brown: So I think what you’ll see, and I’ll ask Darrin to comment on this as well. It will be similar to what we’re doing on Chord assets that are adjacent or in the same area as an Enerplus asset. But of course, the spacing is going to change as you move across the field. And so in — as you’re more in sort of the legacy core, we’ve got slightly tighter spacing in those areas. And there’s a few even in some cases, Three Forks opportunities that we see in the legacy Chord as well. But it all has to do with the subsurface geology. There’s more oil in place in those areas and there’s more separation between Three Forks and Bakken. So you just need to space those wells differently. But we do have a preference for generally wider spacing than others within the basin because we think we actually get similar results, but it’s better capital efficiency.

So you’ll see — I think you’ll see similar spacing to what Chord would have done, but there’s not sort of ubiquitous spacing across the entire basin, but I’ll ask Darrin to weigh in more.

Darrin Henke: Yes, David, in the spirit of continuous improvement, now that we’ve combined our subsurface teams, legacy Chord and Enerplus, we’re really embarking on rolling up our sleeves and really looking at completion intensity coupled with well spacing, the two go hand in hand. And it’s an ever-evolving solution that we’re looking for. Obviously, we’re looking for the most capitally efficient solution. The fewest wellbores in the ground that can produce the reserves most economically, most viably, that’s what we’re looking for. And that — we don’t think that we have the ideal solution today, and I’m not sure we’ll ever get there. It’s something that you got to continuously improve and evaluate. And so we’re right in the middle of that currently, but Danny hit the nail on the head. A lot of the Enerplus acreage will have some Three Forks wells, and we’ll also have some tighter spacing is what we would — one would expect.

David Deckelbaum: Maybe just to revisit, obviously, highlighting the relatively advantaged base decline achieved this year. If you were to distill that down or kind of deconstruct what happened there, would you attribute most of that to the benefit of shallower declines from longer laterals on new organizational wells? Or has it been more optimized workovers and base management that we would expect, obviously, to continue in the ensuing years?

Danny Brown: So I think it’s a combination of several things. It’s — one, we haven’t been pushing a significant growth program through the system, and so that’s obviously helpful in moderating declines as we look forward. I think, certainly, our focus on our — the operating side of the business with making sure our downtime is low that we’re getting wells returned to production quickly, obviously helps as well. In the larger component of 3-mile laterals, which have inherently lower decline is helpful. Also I would say that last one, we’re just starting to see the impact of because if you think about it, we’ve got thousands of wells in the basin and these 3-mile laterals have got about 100 of them. And so they are newer wells and they’re some of our more productive wells, but it still represents a fairly small fraction of the overall production base that we’ve got.

So it’s a combination of things, including the wider spacing we’ve taken — that we’ve done over the last few years. So it’s a myriad of things. But the great news is it’s all sort of — they’re all combining to make that base decline lower, which is just making us a much more capitally efficient producer.

David Deckelbaum: Appreciate the color guys.

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

John Abbott: Hey thank you very much for taking my questions. So I want to go back to the base decline here. Now we look at Slide number 5 where you just basically talk about the percentage of long lateral development. 2022 was 13%. 2024 is 40% long lateral development, granted some of those wells in 2024, as you just mentioned, are just coming online. I guess my question just sort of think about the base decline. If I went back to 2022, what — could you just sort of remind us what your base decline rate was at that period of time versus the 35% that you show currently, 2024? Just to get a sense of the impact of longer laterals on your underlying decline rate.

Danny Brown: Yes, I’d say a little — probably a little higher than this. I can’t give you a specific number. And I think the Enerplus assets obviously clearly make this a little bit of an apples and oranges comparison because the decline rates there through the growth in their program is just really different than what the legacy Chord position had.

John Abbott: Understood. And then my other question goes to the spacing. I mean, you are more conservative on the spacing side there than some of the other folks out there, and you’ve just discussed how the spacing could be different on the Enerplus assets. I guess the question here, Danny, have you been too conservative? Is there an opportunity for to go back to some of these areas where you’ve made this spacing assumptions, maybe to add additional wells there opportunities in your mind for possible inventory expansion on the spacing side at this point?

Danny Brown: John, I think you bring up a great point. And one of the things I think in this business have in humility is a really, really important thing. And so we try to stay humble and know that we can always improve and get better. And that has — I think that lends itself to Darrin’s comments earlier that the teams really have been rolling their sleeves up to go challenge these assumptions and try and figure out what is the most capital efficient, best way that we can go forward and develop this asset. And it could be that we have gotten slightly too wide in some areas. I don’t think it’s going to be dramatic, but considering our acreage position of around 1.3 million acres, a small change in spacing could have a pretty significant impact in inventory.

And so we’re looking into that now. I’ll ask Darrin to weigh in more, but I think developing — making sure we get this right or as right as we can get it is really, really important to us. Danny, any other comments?

Darrin Henke: Yes. I just think, again, spacing is also tied to completion intensity that go hand in hand, and we’ve got a person really got to look at both of those and look at recoveries on a DSU basis to really get a good handle on it. And I never think we’re optimized. So…

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

Danny Brown: Thanks, John.

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

Paul Diamond: Thank you, good morning. Thanks for taking the call. Just want to touch base on kind of that 4-mile opportunity set. Should we be thinking about that as part of this 50% — part of the 50% of longer lateral development in the 2025 to 2027 plan? Or would that be incremental or whatever actually comes into fruition based on how the initial wells go?

Darrin Henke: Yes. So 4-mile laterals are not part of our 2025 to 2027 plan at this point. And you hit the nail on the head, about half of our plan over the next 3 years are not long laterals. And so as — I think we’ll be successful with 4-mile laterals, very confident in that area, where we can take to 2-mile wells and make it a single 4-mile well, that’s absolutely going to improve the capital efficiency and the returns of the single wellbore being at 4 miles versus the 2 shorter laterals. Over and above that, where we can’t necessarily take 2 wells and make one 4-mile well, we’re also looking at U-shaped wells, J-shaped wells, different ways of increasing lateral lengths where we might be constrained to a 2-mile DSU, if we can drill U-shape, J shape.

There’s a lot of different shapes in the industry is really trying right now to get to 3- and 4-mile laterals, we also think that will improve our capital efficiency as well. So none of that is in the 3-year plan at this point.

Danny Brown: Well, I think that what you’re pointing out, it’s an exciting part. If we can move that 50% that’s not longer lateral to a more capital-efficient longer lateral, there’s just a lot of room for additional improvement in the plan going forward. And then the 4-mile laterals just potentially adds on top of that, one, it can help us get the 50% of 2-mile wells into something that’s more capital efficient, or if it’s actually better than 3-mile wells, perhaps you actually have another leg of the stool of additional capital efficiency improvements going forward as well. So there’s two parts of that 4-mile laterals that are exciting.

Paul Diamond: Understood. Appreciate the clarity. And just one quick item on the current hedge book been ticking up for the last few quarters. Is that more in reaction to your long-term view or a shift in strategy? I guess, how should we think about where the — where do you all think the right level is?

Darrin Henke: Yes, I think what you’re seeing is just what we call programmatic hedging. So it’s not — we have — we set out to do — continue to hedge every quarter just layering on hedges, no matter what the kind of the price environment is just to make sure that we march forward with a little bit of protection. But we still continue to believe that people own us for the commodity exposure. And so you see — what you really see in our program, there’s a lot of upside and participation in oil price to the extent it moves upwards.

Paul Diamond: Appreciate the color. Thanks.

Operator: Your last question comes from Noel Parks of Tuohy Brothers Investment Research. Please go ahead.

Noel Parks: Hi, good morning. It came up briefly earlier. But I was wondering how would a gas price rebound scenario sort of ripple through your realizations and your takeaway? I don’t know if there might be a effect on the East versus West parts of your footprint.

Richard Robuck: Yes. I wouldn’t say that it’s a function of our footprint. I really think it’s just a function of the fixed price nature of the contracts, as I described in my prepared remarks. So to the extent gas prices go up, you’ll just see a high torque to the upside on our realizations. I think there’s some exciting developments in Canada, seeing gas potentially starting to move West and LNG Canada facility next year. So we think there’s some positive tailwinds for gas pricing out of the Bakken as we look forward into next year.

Darrin Henke: And Richard mentioned just there’s an operational leverage there because of that fixed scenario. While we’ve been pricing lower because of AECO here recently, that LNG that he just mentioned that could be drawing more gas volumes from Canada West will be potentially very beneficial to the Bakken realization going forward. And hopefully, that stuff comes online middle of next year.

Noel Parks: Great. Thanks. I hadn’t really thought about or heard that talked about a lot, so that’s really interesting. And as far as the synergies that you’ve achieved with Enerplus, I mentioned some of them are kind of more upfront day one type savings. And could you just give a sense of what are the still remaining synergies to capture some of them have to do with contracts rolling off and so forth?

Danny Brown: Well, certainly, there’s a degree — there’s a degree of that as opportunity as we move forward. As we think about the 3-year plan, which you talked about, I think the capital synergies are largely included in that plan over that 3-year time frame. From an operational perspective, one thing that we’ll see is, I think, increasing synergy capture as we move into 2025. And so we’ve been able to capture some of the operational synergies to date, but we still have some remaining because we really changed some of our approach in the field from an operational perspective. And so that includes things like the way we run rods and our wells. There’s different practices between the 2 legacy organizations that we think will lead to fewer rod failures in the future.

And so that’s going to improve our work. That really probably won’t start materializing until we get into next year. And we also have a bit of a capital dis-synergy that’s baked into all of our plans and that we tail into our completions with resin coat. And we think that it helps keep sand from flowing back in the wellbores, which really rigs have it with our ESPs and our run times there. And so fewer ESP failures, we also anticipate seeing in the future because we’re taking our upfront capital and completion practices are a little different — were a little different between the legacy organization. So some of the capital — some of the synergies baked into the plan, but still see some upside as we go into 2025 from an operational perspective.

Noel Parks: Great. Thanks a lot.

Operator: Thank you, ladies and gentlemen that concludes our question-and-answer session. I will now turn the conference back over to CEO, Danny Brown. Please go ahead.

Danny Brown: Well, thank you, Dion. So to close out, I want to let the organization know how grateful I am for their continued strong performance and dedication to continuous improvement. The Bakken is a world-class resource with strong economics. And as a premier operator in the basin, Chord sees a wide array of opportunities to drive efficiency and accelerate Chord’s rate of change as it relates to economic returns and value creation. I want to thank all of our employees for their continued hard work and dedication. And with that, I appreciate everyone’s interest, and thanks for joining our call.

Operator: This concludes today’s conference. Thank you for attending. You may now disconnect your lines.