Good morning, ladies and gentlemen, and welcome to the Chord Energy Q3 2024 earnings call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, November 7, 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 Q3 2024 financial and operational results. We are delighted to have you on the call. I'm joined today by Danny Brown, our CEO, Michael Lou, our Chief Strategy and Commercial Officer, Darrin Henke, our COO, Richard Robuck, our CFO, 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 that 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 Q3 performance and resulting return of capital before turning the discussion to our three-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 Q4 oil volumes to be about 900 barrels of oil per day, which is reflected in our guidance. Turning to Q3 results, Chord delivered another great quarter with solid operating results, yielding free cash flow above expectations, which supported robust shareholder returns. Specifically, Q3 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 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 Q4 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 Q3. 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 three-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 152,000-153,000 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 four-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 Q3, 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, water disposal constraints, downtime related to artificial lift installation, testing, or a host of other factors that have nothing to do with a well's inherent productive capacity and expected ultimate recovery. Second, there is also variability across the basin on flowback methodology. In some instances, wells are brought online at high IPs 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 cums are among the best in the basin, while our three-month cums are more average performers. 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 per-foot 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 three-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, the 2024 program starts off a little below 2023 but quickly catches up and ultimately surpasses last year due to a higher concentration of three-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 even 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 the past few years, while D&C cycle times and clean-outs continue to improve. This quarter, we formally updated our third-mile productivity assumption to be essentially identical to the first 2 mi. 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 three-year plan where performance improvement is driven by operational advancements and synergy capture. Chord 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 six of our eight fastest wells being drilled in the Q3. 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 simul frac operations on most pads, which has driven down non-productive time, leading to well cost savings and getting production on quicker. Simul frac has resulted in a 40% increase in frac 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 Q3 results and then discuss updates to our guidance. In the Q3, 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 Q3 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 Q2, and that dislocation continued into the Q3. 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% 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 cost of $17.5 million. Production taxes averaged 9% of commodity sales in the Q3, 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 30th, Chord had $470 million drawn on its $3 billion credit facility, which has $1.5 billion of elected commitments. Liquidity as of September 30th 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 Q3, Chord repaid $63 million of Enerplus senior notes, and net debt decreased by $20 million, even as we paid out our Q2 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 its second consecutive volume guidance increase this year. The midpoint of our Q4 oil guide of 152,000 barrels of oil per day would have been approximately 153.3 thousand barrels of oil per day, adjusting for the impacts of the DJ Basin 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 Q4 guide. Our marketing team continues to deliver basin-leading oil differentials. NGL realizations are expected to be similar to the Q3, 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 out and further in time, realizations should also improve quickly in environments where gas prices rise. On the cost side of the business, we're 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%-5% of adjusted EBITDA in the Q4 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%-11% at prices of $60-$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 Q4 and since our last update, so our derivatives position as of November 5th can be found in our latest investor presentation. In closing, the team's hard work on integrating the Enerplus asset while at the same time improving day-to-day operations gives me great conviction in our ability to deliver our three-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. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the number one on your touch-tone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question comes from Neal Dingmann of Truist Securities. Please go ahead. Morning, guys. Nice quarter. My first question is around that, like that three-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? Yeah, 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 hadn't reached the station on that. I expect we will continue to see increased efficiencies relative to what we put in this plan. And if and when we do see that, we're going to not increase activity. We won't be managing to sort of holding a capital level flat and let production float up. We're likely to do the exact opposite, just kind of maintain a flattish production profile. If we need to spend less capital to do so, fantastic, and we'll just let some more free cash flow flow through the system. Yeah, I was hoping you'd say that. And then, Danny, Mike, go ahead, guys. 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. Yeah, I'd say the plan is really sort of geared 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 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 think, 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 sort of 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. 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 break-evens? I don't know, like if you look in the west in Williams, McKenzie counties versus going east around Mountrail and Dunn, how different do break-evens now suggest? You know, 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, we're just due to the legacy development plan, we're probably more two-mile lateral development there. And so if you look at the three-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 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, is you're able to deliver returns that are pretty similar to the core. Now, the underlying geology in the core continues to be better. And so for sort of same same, the core is core, but we've been able to generate economic returns that are similar to the core moving out west by drilling longer and spacing a little wider. Great. Thank you, Dan. Thanks, Neal. Your next question comes from Scott Hanold of RBC. Please go ahead. Yeah, thanks. I was wondering if you could provide some color on those updated three-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 closer to the toe? Yeah, 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 that 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, but needed to see the data and see how the wells actually performed, and so now that we've got that data, we're very confident on how we look here and have been really, really pleased with what we're seeing from that third mile, so I'll turn it over to Darrin for incremental comments. Yeah, 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've brought online really in the last 12 months or so, you see the benefits of that and the production, as our engineers forecast the reserves, look spot on to be 150% of a two-mile well for our three-mile wells. So same recovery on a per foot basis. Okay. Thanks for that. And my follow-up is on the, or I guess, three-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, Danny, you kind of mentioned the $1.4 billion is kind of based on what you know today. Can you give us some context of is that contemplating all the full synergies or what is the benefit of getting the full synergies? 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 going to be pretty ratable, or is there going to be certain areas that get more focus in certain parts of the plan? Yeah, 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. And so we've got the rigs and drilling and completion crews a little bit spread out across the field. And so I think we'll continue that. 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 three-year timeframe. With respect to opportunities to improve the plan, I'd say clearly service cost will follow activity, which will follow oil price. We'll see where overall pricing goes, which is going to set activity levels, which service cost will be pinned off of that. 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. As we could see service costs come down, that would float 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. I think we've got a slide in the deck showing some of the improvements in D&C cost 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, Scott, is that this doesn't contemplate really any benefit from four-mile wells. And so we're drilling one of those. We've spudded one now. We'll see results. I personally have high hopes and expectations around four miles, but that's not contemplated in this plan at all. And so as we see success with four-mile wells, potentially converting two-mile wells over to four-mile wells, that's just upside that we would see here as well. Yeah, and just to clarify, the synergies, is that fully in there that 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 sort of the continuous improvement and efficiency improvement because at some point, what's a synergy and what's just getting better? And what I know is we're just getting better. Got it. Thank you. Thanks, Scott. Once again, should you have a question, please press star followed by number one. Should you wish to decline from the polling process, please press star followed by number two. Your next question comes from Noah Hungness of Bank of America. Please go ahead. 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 TD on the extended laterals? Yeah, no, good question. It really comes down to the bottom hole assembly that we use and 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. Makes sense. And then you guys continue to mention that you're looking to incorporate three-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? Yeah, we are believers in three-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 three-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 stack two miles together. It's sort of a section of two miles that need to be developed two 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 three miles. And so you'll see some of that in the 2025 plan. Although where we have opportunity to move to three miles, we'll do that as well. So I say it's going to be a mix, probably tilting more towards two miles just because of that legacy development program that surrounds it. But you'll see some three miles too. Makes sense. Makes sense, guys. Thanks. Thank you. Our next question comes from Phillips Johnston of Capital One. Please go ahead. Hey, thanks for the time. Appreciate the color on the three-year outlook. Maybe just to 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? 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. Really the intent of the three-year plan was to give directional guidance here. I'll talk directionally about what we're expecting as we move forward. We're expecting to see as we've got the plan laid out currently, we're going to see, I'd say, our operated well count decrease slightly as we move forward. That's going to be largely driven by increased lateral length. As we're drilling out further, we don't need as many wells to roll through the system in order to deliver the plan. You'll see that creep down a little bit. 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. All right. Sounds good. And I think you guys make a good point on these longer laterals having a positive impact to your base PDP decline rate. And I like the chart on page eight 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 three-year plan that's with the higher mix of the three-mile laterals? 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 would be beneficial for us, obviously, as the program is made up with a larger portion of three-mile laterals, which have inherently shallower decline. And we've sort of got a little bit of certainty with the legacy Enerplus assets, that was a growing asset that we're going to be going more to a maintenance standpoint as we move forward. So both of those things should be beneficial from a decline perspective. Sounds good. Thanks, Danny. Thanks, Phillips. 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% of the program this could kind of migrate towards over the next 12-18 months? And are these savings already included in the latest set of D&C cost figures that you all provided last night? Yeah. So as we look forward, Oliver, the next year's plan, we're probably looking at roughly one and a half frac crews and the one 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, the half a crew. And I'll tell you the feet per day that we're getting fracked as we switch to simul-fracking, 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 three-year plan. Thanks. 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 the 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 a 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'd say share repurchases have always played a part of our program. And so as we've looked through this, we've been really 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 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. 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 leaning 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 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 represented the entire quarter of buybacks that we did. Perfect. Thanks for the time. Thanks, Oliver. Your next question comes from David Deckelbaum of TD Cowen. Please go ahead. Yeah. 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 awaiting 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 and acreage now, or is it going to be on tighter spacing just based on the development there? 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 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 core 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. 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'd ask Darrin to weigh in more. Yeah, 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 capital efficient solution, the fewest well bores in the ground that can produce the reserves most economically, most viably. That's what we're looking for, and 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 one would expect. All right. Perfect. And 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 newer vintage wells, or has this been more optimized workovers and base management that we would expect, obviously, to continue in the ensuing years? So I think it's a combination of several things. One, we haven't been pushing a significant growth program through the system, and so that's obviously helpful in moderating declines as we move forward. I think certainly our focus on 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. And the larger component of three-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 in these three-mile laterals, we've got about 100 of them. And so they're 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 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 capital efficient producer. Appreciate the color, guys. Thanks, David. Your next question comes from John Abbott of Wolfe Research. Please go ahead. Hey, thank you very much for taking our questions. So I want to go back to the base decline here. I want to look at slide number five 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, 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 in 2024, just to get a sense of the impact of longer laterals on your underlying decline rate? Yeah. I'd say 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. 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 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 the spacing assumptions, maybe to add additional wells? Is there opportunities in your mind for possible inventory expansion on the spacing side at this point? John, I think you bring up a great point. And one of the things I think in this business, having 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 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 making sure we get this right or as right as we can get it is really, really important to us. Darrin and other comments? Yeah. I just think, again, spacing is also tied to completion intensity. They go hand in hand. And you've got to. A person really has 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. Appreciate it. Thank you very much for taking our questions. Thanks, John. Your next question comes from Paul Diamond of Citi. Please go ahead. Thank you. Good morning. Thanks for taking the call. I just want to touch base on kind of that four-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 for whatever actually comes into fruition based on how the initial wells go? Yeah, so four-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 three years are not long laterals, and so I think we'll be successful with four-mile laterals. I'm very confident in that area. Where we can take two two-mile wells and make it a single four-mile well, that's absolutely going to improve the capital efficiency and the return of the single wellbore being at four miles versus the two shorter laterals. Over and above that, where we can't necessarily take two wells and make one four-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 two-mile DSU. If we can drill U-shape, J-shape, there's a lot of different shapes the industry is really trying right now to get to three and four-mile laterals. We also think that will improve our capital efficiency as well, so none of that is in the three-year plan at this point. I think that what you're pointing out is 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 four-mile laterals just potentially add on top of that. One, it can help us get the 50% of two-mile wells into something that's more capital efficient. Or if it's actually better than three-mile wells, perhaps you actually have another leg at the stool of additional capital efficiency improvements going forward as well. So there's two parts of that four-mile lateral that are exciting. Understood. Appreciate the clarity. And just one quick bookkeeping item on the current hedge book been picking up in the last few quarters. Is that more in reaction to your long-term view or shifting strategy? I guess, how should we think about where do you all think the right level is? Yeah. I think what you're seeing is just what we call programmatic hedging. So it's not we set out to continue to hedge every quarter, just layering on hedges no matter what 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 what you really see in our program is a lot of upside and participation in oil price to the extent it moves upward. Good. Appreciate the clarity. I'll leave it there. Thanks. Your last question comes from Noel Parks of Tuohy Brothers Investment Research. Please go ahead. 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 different effects on the east versus west parts of your footprint. Yeah. 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 into that 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. And Richard mentioned just that 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. 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 imagine 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. Certainly, there's a degree of that as opportunity as we move forward. As we think about the three-year plan we just talked about, I think the capital synergies are largely included in that plan over that three-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 in our wells. There's different practices between the two legacy organizations that we think will lead to fewer rod failures in the future. And so that's going to improve our workload. That really probably won't start materializing until we get into next year. And we also have a bit of a capital D&C synergy that's baked into all of our plans and that we tie into our completions with resin coat. And we think that helps keep sand from flowing back in the wellbores, which really wreaks havoc with our ESPs and our run times there. And so fewer ESP failures we also anticipate seeing in the future because our upfront capital and completion practices are a little different. We're a little different between the legacy organizations. So some of the capex, some of the synergies baked into the plan, but still see some upside as we go into 2025 from an operational perspective. Great. Thanks a lot. 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. 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 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. 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.