Good morning, ladies and gentlemen, and welcome to the Chord Energy Third Quarter 2024 Earnings Call. 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.

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.

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 costs 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, we 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 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, and 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 initial production rates and sharper declines. While in 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 production performance is among the best in the basin, while our 3-month performance is more average. Note as well that as we move to longer laterals, we are not moving our initial production rates up in lockstep with the increased lateral length. So as the average lateral length of the program increases, when looking at well 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 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 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.

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 drilling and completion cycle times and cleanouts continue to improve. This quarter, we formally updated our third-mile productivity assumption to be essentially identical to the first two miles. Slide 7 of our investor presentation highlights over 60 3-mile wells with sufficient production history to illustrate that 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 total depth 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 ultimate recoveries with substantially fewer 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. The 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 specifications, 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 hydraulic fracturing operations on pads, which has driven down nonproductive time, leading to well cost savings and getting production online quicker. Simul-fracturing has resulted in a 40% increase in fracked feet per day. Our operations team has driven costs down across the entire wellbore, including proppant 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.

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, 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 result in lower realization as a percentage of benchmark price. Turning to operating costs. Lease operating expenses were below expectation at $9.56 per BOE, reflecting better downtime and lower workover costs. Cash general and administrative expenses were $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 contributions in our revenue mix. Cash taxes of $13 million were below our expectations. Capital expenditures of $329 million were 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 in 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 guidance 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 guidance. 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 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 lease operating expenses and general and administrative expenses quarter-over-quarter. Our general and administrative 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 assets, 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.

Your first question comes from Neal Dingmann of Truist Securities. Please go ahead.

Good morning, guys. Nice quarter. My first question is around 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 see the free cash flow boost?

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 if we see that, we're likely to do the exact opposite, just kind of maintain a flattish production profile. And if we need to spend less capital to do so, fantastic, and we'll just let some more free cash flow through the system.

I was hoping you'd say that, so please go ahead. Were you going to say something?

No, what was your first question again, Neal?

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

Yes, I'd say the plan is really sort of geared around our 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 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 accordingly and allocate capital accordingly. So if we saw dramatically lower commodity prices, we would have to think about what the market is telling us and how we choose 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 I'd call it around a band of where we're at today; we think this plan is a solid and very, very achievable one, maybe somewhat conservative, and we expect to be able to deliver upon it or do a little better.

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?

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, we're probably more at a 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 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. We'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 similar setups, 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 and in space a little wider.

Great. Thank you, Dan.

Thank you.

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

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 some of the challenges or physical challenges that you have overcome as you obviously get out closer to the toe?

Yes. Thanks, Scott. 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 sort of move up from this 80% scaling factor for the third mile to 100% scaling factor is, 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.

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

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 are 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, how do you think about the mix on a year-to-year basis as it progresses through it? Is it pretty ratable? Or are there areas that get more focused in certain parts of the plan?

Yes. So I think as we look at the overall development plan, we are expecting to see that our operated well count decreases slightly as we move forward. That's 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-operated. We just brought a lot of non-operated into the system with both the XTO acquisition and with Enerplus. These are wells in the core of the field, and they are really compelling investment opportunities. So we'll be putting a little bit more into those as we move forward. I would say that what we've got contemplated in the plan currently is essentially what we're seeing currently in the latter half of 2024, but that's the well costs we have assumed in the plans as we move forward. So as we 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 our teams do is get more and more efficient, quarter-on-quarter. And I think we've got a slide in the deck showing some of the improvements in drilling and completion costs we've seen over the past year. Again, I don't see that slowing down anytime soon.

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?

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 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.

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

Good morning, everyone. I would appreciate it if you could provide some operational insights regarding how you were able to get coiled tubing to total depth on the extended laterals.

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. Someone might argue it's a competitive advantage for Chord. So I'll leave it at that.

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 think those extended laterals on that acreage would be incorporated into the development plan?

Yes. 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 does not lend itself for 3-mile development because there is existing development that would preclude you from going out to the third mile. So we won't be able to transfer all of their wells over to 3 miles. 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.

Makes sense, guys. Thanks.

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

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?

Thank you for your question, Phillips. I'll provide some directional insights on this matter, as we will release specific guidance in February. The purpose of our 3-year plan is to offer directional guidance, so I will share our expectations as we move ahead. We anticipate a slight decrease in our operated well count as we progress, primarily due to longer lateral lengths. This means that as we drill farther, we won't need as many wells to execute the plan. You will notice a small reduction in operated wells along with a slight increase in non-operated wells. We've recently added several non-operated wells to our portfolio through the XTO acquisition and Enerplus, and we plan to increase those moving forward. While I don't have an exact number for you, I do expect some downward pressure, which will be advantageous for us since our program will consist of a larger share of 3-mile laterals, which typically experience shallower declines. Overall, both factors should be beneficial regarding declines.

Alright. Sounds good. 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?

I don’t have a specific number for you, Phillips. However, I do expect it to face some downward pressure, which will be beneficial for us since the program consists largely of 3-mile laterals, which typically have shallower declines. Additionally, we have some certainty with the legacy Enerplus assets, which were previously growing and will now shift more towards a maintenance approach as we progress. Both of these factors should help improve our decline outlook.

Thanks, guys. Thanks, Danny.

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

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?

Yes. So as we look forward, Oliver, the next year's plan, we're probably looking at roughly 1.5 frac crews and 1 full-time dedicated frac crew. Our plan is to do simul-fracs the entire year with that frac crew. And then the other crew will be more of a zipper frac crew, half a crew. The feet per day that we're getting fracked as we switched to simul fracking is impressive. 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 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.

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 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?

Thanks for the question, Oliver. I would say share repurchases have always been a part of our program. We’ve been repurchasing shares in all environments, and given the current landscape, we think it's a particularly compelling opportunity. We have consistently engaged in share repurchases, and in the near term, we certainly plan to focus heavily on them. However, I believe share repurchases will continue to play a significant role in our overall strategy.

Absolutely. I would add that with the Enerplus transaction, there were times when we couldn't buy shares. It may have seemed like we were unable to act, but that wasn't the case; we simply couldn't make purchases during those periods. Looking back at June, after we closed the transaction, we made significant buybacks, which accounted for the entire quarter's activity.

Your last question comes from David Deckelbaum of TD Cowen. Please go ahead.

Thank you for your time this morning. I wanted to confirm your thoughts on the plan from 2025 to 2027. As you move into more of the Enerplus acreage, particularly in 2026 and 2027, will the spacing be the same as for the legacy Chord wells, or will it be tighter due to the development in that area?

What you'll see is that it will be similar to our approach with Chord assets located near Enerplus assets. However, the spacing will vary across the field. In the legacy core areas, we maintain slightly tighter spacing, but we generally prefer wider spacing compared to others in the basin, as we believe this approach yields comparable results while being more capital efficient. You'll notice similar spacing to what Chord has implemented, although there won't be a consistent spacing throughout the entire basin. I'll let Darrin provide further insight on this.

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. 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, that's what we're looking for. We don't think 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 associated Three Forks wells. We'll also have some tighter spacing as one would expect.

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 to continue in the ensuing years?

I believe it's a mix of factors. First, we haven't implemented an extensive growth program, which has helped reduce declines as we look ahead. Our attention to operational efficiency, ensuring minimal downtime and swiftly returning wells to production, has also contributed positively. Additionally, the increased presence of 3-mile laterals, which naturally have lower declines, plays a role. Lastly, we're beginning to see the effects of our newer wells; while we have thousands in the basin, around 100 are 3-mile laterals, which are some of our more productive wells. However, they still make up a relatively small portion of our total production. Overall, these factors are combining to lower the base decline, making us a more capital-efficient producer.

Appreciate the color guys.

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

Thank you for taking my questions. I want to revisit the base decline. Looking at Slide 5, you mention the percentage of long lateral development, which was 13% in 2022 and is projected to be 40% in 2024. Some of those wells in 2024 are just coming online. Could you remind us what your base decline rate was in 2022 compared to the current 35% you indicate for 2024? I'm trying to understand how longer laterals impact your underlying decline rate.

Yes, I would say it is probably somewhat higher than this. I can't provide a specific number. Additionally, the Enerplus assets create a slightly different comparison because their decline rates, due to growth in their program, are significantly different from what the legacy Chord position experienced.

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 you to go back to some of these areas where you've made these spacing assumptions, maybe to add additional wells there opportunities in your mind for possible inventory expansion on the spacing side at this point?

John, you raise an excellent point. In this business, maintaining humility is crucial, and we strive to remain modest and aware that we can always improve. This aligns with Darrin's earlier comments about our teams actively questioning our assumptions and seeking the most capital-efficient approach to develop this asset. It's possible we've become somewhat too broad in certain areas. While I don't expect a drastic change, given our acreage position of about 1.3 million acres, even a minor adjustment in spacing could significantly affect our inventory. We're currently examining this. I'll let Darrin provide additional insights, but ensuring we get this aspect right is very important to us. Danny, do you have any further comments?

Yes. I just think, again, spacing is also tied to completion intensity that goes hand in hand, and we've got to really look at both of those and look at recoveries on a drilling spacing unit basis to really get a good handle on it. And I never think we're optimized. So...

Appreciate it. Thank you very much for taking our questions.

Well, thank you, Dion. 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. 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.

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