Good morning, ladies and gentlemen, and welcome to the Chord Energy Second Quarter 2024 Earnings Conference 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, August 8, 2024. I would now like to turn the conference over to Bob Bakanauskas, Managing Director of Investor Relations. Please go ahead. Thanks, Matthew, and good morning, everyone. This is Bob Bakanauskas, and today we're reporting our second quarter 2024 financial and operating results. We're delighted to have you on the call. I'm joined today by Danny Brown, our CEO; Michael Lew, our Chief Strategy and Commercial Officer; Darrin Henke, our COO; and Richard Robuck, our CFO, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to the risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls. Those risks include, among others, matters that we have described in our earnings releases, as well as 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. With that, I will turn the call over to our CEO, Danny Brown. Thanks, Bob. Good morning, everyone, and thank you for joining our call. I recognize it's a very busy morning, so I plan to provide a brief overview of our second quarter performance and our return of capital, as well as updates on our full-year outlook. Additionally, I'll give some color on our integration with Enerplus before passing it to Darrin. Darrin will give details on operations and synergies before passing it to Richard for a little more on our financial results. We'll then open it up to Q&A. So in summary, Chord delivered another great quarter, which resulted in strong shareholder returns. So diving in, second quarter oil volumes were toward the top end of guidance, driven by strong well performance and less downtime. Capital was below expectations, reflecting some timing adjustments to the program, and Lease Operating Expense also came in favorable versus our expectations, reflecting less downtime and lower maintenance costs. Many thanks to our operating team for delivering favorable results really across the board. Well done. Given this strong quarterly performance, free cash flow was above expectations, and on a pro forma basis, adjusted free cash flow was approximately $263 million. This includes a full quarter of Enerplus's results and excludes approximately $16 million of non-operated capital, which was not contemplated in original guidance and will be reimbursed through asset divestitures. In accordance with our return of capital framework, Chord will return 75% of this adjusted free cash flow to shareholders. To that end, given our base dividend of $1.25 per share and our normal course share repurchases in the second quarter of $41 million, we declared a variable dividend of $1.27 per share. I would note that the timing of our share repurchases was somewhat impacted by the possession of material non-public information associated with the Enerplus acquisition and various filings made during the quarter. Additionally, last night, we issued third quarter and updated full-year guidance. As we discussed in May, the development program went faster than expected in the first half of the year due to strong performance and a fairly mild winter. This resulted in volumes in capital above our original expectations early in the year. As I've mentioned before, Chord is focused on efficient and sustainable free cash generation, which results in us executing a maintenance plus program. We do not plan to increase capital this year, even as we raise our full-year oil guide by 500 barrels per day. With that in mind, Chord slowed frac activity and is currently down to 1 frac crew versus 3 pro forma earlier in the year. This crew count will increase as we move into late summer and fall and result in Chord being toward the lower end of its full-year operated new well turn-in-line range. Concurrently, Chord is increasing non-op spending in the second half of the year, as the team is investing in a number of attractive non-operated opportunities that we acquired in our transaction with the XTO and our combination with Enerplus. Net of these offsetting impacts, full-year capital guidance is unchanged. I should note that when looking at capital, you'll likely notice that capital and LOE guidance reflects some accounting changes as a result of the Enerplus combination that Richard will discuss in more detail. In a nutshell, on an apples-to-apples basis, pro forma capital is unchanged versus our May outlook, while LOE is running favorable versus our initial expectations. As I mentioned a few moments ago, we will be increasing our expected full-year oil volumes by 500 barrels per day to account for the good performance we've seen to date. Turning to Enerplus, the combination closed as expected on May 31st. We remain extremely confident in the strategic and financial benefits of the transaction, and as we move through integration, our conviction level continues to grow. Enerplus brings top-tier assets in the core of the basin, and we expect Chord can enhance returns on these assets by applying techniques it has developed over the past several years, including longer laterals, optimized spacings, and reducing downtime. The combined asset base supports efficient operations, strong returns, sustainable free cash flow, and a peer-leading return of capital program. Our integration efforts are going well, and by utilizing combined best practices and enhanced scale, we are very confident in achieving the greater than $200 million synergies target, which is up from our original estimate of $150 million. Slide 11 in our deck highlights some of our recent operational, some of our recent operational progress and opportunities to improve the combined company going forward. I want to let the organization know how grateful I am for their continued positive attitudes and dedication in driving an effective integration and pushing to realize incremental value from the transaction. And importantly, no one has taken their eye off the ball, and Chord is currently putting up great operating results. Also, in our updated presentation, you will see some new material focused on helping investors better understand how attractive the Williston Basin is, and I believe our technical, operational, and marketing teams have been instrumental in driving what we think is a resurgence of the basin. The Williston Basin continues to evolve, and the current state of play is worth revisiting. Number one, it has the highest oil cut of any major onshore Lower 48 basin, which supports strong margins and impressive returns. Second, with our footprint basically extending across the entirety of the play, our subsurface understanding is both differential and fulsome. With our learnings, we generally target only the Bakken, which means parent-child interference can be more accurately modeled. This isn't well understood, in my opinion, but it is an important competitive advantage. The upper right-hand chart on slide 10 shows well productivity adjusted for volatility across basins, a bit of a pseudo Sharpe ratio, if you will. The Bakken screens very well on a risk-adjusted basis, as the wells are prolific with lower relative variance. Third, the land and regulatory environment is excellent, and as an added benefit, Chord has been the leader in longer lateral development compared to other lower 48 peers. Longer laterals are a more efficient way to develop the resource and support strong returns, as well as Chord's low reinvestment ratio. Lastly, oil takeaway has really improved differentials over the past decade or so, and Bakken crude has traded consistently close to WTI for many years running. To sum it up, the Williston is a phenomenal place to do business, and the Chord team is focused on making every aspect of the business better and continuing to improve our returns. And finally, we remain committed to delivering affordable and reliable energy in a sustainable and responsible manner. Chord's culture revolves around continuous improvement and is focused on driving performance across a number of key areas, including emissions and safety. Chord expects to publish a sustainability report later this year on a legacy Chord-only basis and also provide a summary of key ESG and sustainability metrics for Enerplus. In 2025, we expect to publish a full sustainability report reflecting the combined company. So to summarize, Chord delivered a great start to the year, which essentially accelerated the production profile into the first half and should result in high free cash flow and shareholder returns in the second half of the year. We remain as excited as ever on the Enerplus transaction and look forward to executing in 2024 and beyond. And with that, I'll turn it to Darrin. Thanks, Danny. We had a solid quarter on the operations front as the team continues to execute with excellence. Our wedge production benefited from robust well performance, while our base production benefited from lower levels of downtime. I thought we'd spend a little time talking about Chord's asset base and the kind of things we're doing to make great assets even better. First, most of you know that Chord is the leader in three-mile lateral development. Slide six on the bottom left shows Chord's longer lateral wells as a percent of the program last year, and as you can see, we're at the top of the peer group. The upper right chart shows Chord's longer lateral well productivity in the Williston Basin compared to peers. Since the second half of last year, which is when we started to consistently reach total depth on post-frack cleanouts. Again, Chord is at the top of the pack. It was early days at Enerplus relative to three-mile laterals, and we see an opportunity to high-grade our new asset by applying Chord's technical expertise. 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. While some outperformance is already being captured in our PDP-based forecast, we currently model three-mile wedge wells delivering approximately 40% more EUR for 20%-25% more capital. It's likely that we're getting more than the 40% uplift, especially since the team has improved the coil tubing cleanout process, whereby Chord routinely reaches TD on most wells. We expect to formally update the market on our three-mile productivity assumption in November as part of our third quarter results. Across the portfolio, we certainly like what we see relative to productivity, decline rates, and flowing pressures. Referring to slide seven, the chart on the upper right shows Chord's average spacing across the basin is wider than other operators. This up-spacing has helped keep declines shallow, production flat, and reinvestment rates low. As we integrate the Enerplus assets, we think an opportunity exists to optimize spacing and enhance the economic returns of the overall development program. Wider spacing has been a key driver to improve Chord's capital efficiency in recent years. The lower half of the chart shows a case study from Enverus, which assesses Chord's widely spaced well performance versus those in a neighboring DSU with tighter spacing. The result is similar DSU recovery in aggregate, with Chord deploying substantially less wells and capital. Continuing with well spacing, slide eight shows Chord's success with wider spacing across the entire basin. Again, Chord is draining most, if not all, of the DSU with fewer wells and materially less capital than our peers. Chord continues to evaluate opportunities to maximize capital efficiency and continually analyzes the merits of removing or adding wells across our position. Just a couple quick thoughts on synergies before passing it to Richard. Like Danny mentioned, as the teams get deeper into the integration, we continue to like what we see. On slide 11, we highlighted some key items where we see considerable opportunity. Chord is the leader in drilling times in the Williston Basin, and by applying Chord's drilling techniques, we have already seen improvements in drilling performance on the Enerplus asset since closing just a couple of months ago. Additionally, Chord has increased completion efficiencies over the past year with its legacy Zipper fracs. We expect to achieve further efficiency improvements with the simulfrac completions that Enerplus used extensively. Finally, I wanted to highlight our progress in reducing downtime over the past 12-18 months. As you can see on the right-hand side of the slide, the Chord team has made significant improvements on this front, and we see a meaningful opportunity to lower downtime on the new areas of our expanded portfolio. To sum it up, Chord continues to execute quite proficiently, and I want to give credit to a team that pushes innovation and relentlessly strives for continuous improvement. It's a really exciting time for the company, and Chord will further advance these top-notch assets, jumping the S-curve by applying its technical and operational expertise. I'll now turn it over to Richard. Thanks, Darrin. I'll walk you through the second quarter results, which include contributions from Enerplus after the combination closed on May 31st. Guidance for the remainder of the year reflects a contribution from both companies. You'll notice a handful of key guidance items look different than what you might have expected by looking at Chord and Enerplus standalone financials. Certain reclassifications have been made in the historical presentation of Enerplus's financial statements to conform to Chord's accounting policies and presentations. Enerplus expensed certain items through LOE that Chord will deduct through gas and NGL revenue or charge through capital. Additionally, Enerplus capitalized certain G&A charges that Chord will expense. The net impact of these changes relative to Enerplus's standalone reporting is lower LOE, lower gas and NGL revenues, and slightly higher capital and G&A expense. The impact of the accounting changes is neutral to adjusted free cash flow. Slide 18 in the investor presentation bridges the impact between the accounting policy alignment differences. In the second quarter, Chord generated adjusted free cash flow of $263 million on a pro forma basis. Strong volumes as well as lower operating costs and lower capital offset weaker-than-expected pricing, especially for natural gas and NGLs. Oil volumes were strong in the second quarter, about 1% over midpoint guidance, and total volumes were about 2% [audio distortion] Hi, this is Richard Robuck again. Apologize for the interruption. A little technical difficulty on our end, but I'm gonna kick back up where I think where we lost you. So we were talking about WTI realizations, and we were noting where we were versus WTI for our differentials at $1.71 in the second quarter, and we expect that to improve in the second half of the year. NGL realizations as a percent of WTI were approximately 11% in the second quarter, and natural gas was 27% of Henry Hub. Looking forward, our guidance reflects market expectations placed on top of our cost structure. As a reminder, certain marketing fixed fees are deducted from our gas and NGL prices. This drives higher operating leverage, which hurts realizations for both NGLs and gas in the times of weaker prices. With gas prices trading at low levels, the fees deducted from our price results in lower realizations as a percent of the benchmark price. However, realizations should also improve quickly in environments where gas prices rise. Turning to cost, LOE was $9.37 per BOE in the second quarter, which on a comparable, comparable basis, was below our expectations, reflecting better downtime and lower maintenance costs. Looking forward, we expect this to increase some in the back half of the year, which modestly reflects workover timing. Cash GPT was $3.18 per BOE in the second quarter, which we expect to come down a bit in the second half of the year. Cash G&A, excluding merger-related costs, was $21.8 million in the second quarter. Merger costs were $54.7 million during the second quarter. We expect this to step down materially in the back half of the year. Our cash G&A guidance excludes the impact of merger-related items. Production taxes averaged 8.8% of commodity sales in the second quarter, and we expect this to come down in the second half. North Dakota recently lowered the production tax on natural gas to approximately 6.5 cents per Mcf from 14.23 cents previously, which is related to trailing gas prices. Second half cash taxes are expected to be 6%-12% of adjusted EBITDA, which is down from our original expectations for the second half cash taxes of 8%-14% that we discussed in May. Chord's full-year cash tax expectations are slightly lower than our original guidance as well. As of June 30th, Chord had $575 million drawn on its $1.5 billion credit facility. Liquidity as of June 30th was about $1.1 billion, including $197 million of cash and $895 million available on the credit facility, net of letters of credit. Net leverage was 0.3x at June 30th, consistent with expectations that we set out in May when we announced the transaction closing. Subsequent to the quarter, Chord repaid approximately $63 million of Enerplus senior notes. Additionally, Chord put on some hedges since our last update. Our derivative position as of August 6 can be found in our latest investor presentation. In closing, it's been an exciting time for Chord. I'd like to sincerely thank the entire team for their hard work and dedication to the company. Your efforts have put the company in a strong position to succeed going forward. With that, I'll hand the call back over to Matthew for questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the number one on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press star followed by the number two. If you are using a speakerphone, please leave the handset before pressing any keys. One moment, please, for your first question. Your first question comes from Scott Hanold of RBC. Please go ahead. Your line is open. Hey, thanks, all. I have a question on, It seems like you remain pretty confident in your three mi EURs, you know, with your across your basin with your latest update, and also the strategy of wider spacing seems like it's working out really nicely. Now, as you start to think about your 2025 development strategy, can you remind us, you know, how much of that is being contemplated on, you know, say, core legacy assets versus Enerplus? And are you gonna be able to quickly, you know, reorientate the lateral length and the spacing on some of the Enerplus acreage? So we'll, you know, see some of that hit the ground running as you get into 2025. Thanks, Scott. This is Danny. You know, as we know—as you know, we're putting together the 2025 full development plan currently. So I think we'll talk probably more about that at the end of the year. The intent would be, you know, as we've mentioned on a couple of previous occasions, we've seen tremendous benefit from having some diversity in, let's call it, the geographic location of our various development programs, rigs, and crews. The reason is, if we concentrate in any one area too much, we end up overwhelming the system in that area. We overload our midstream providers, we overload, candidly, we overload sometimes the people that are in that spot. There's just a bit of a portfolio effect that we benefit from if we spread the program out a little bit. We do recognize the core nature of the Enerplus, the acquired Enerplus acreage position. As we can look at particularly maybe drilling those wells a little longer or spacing those wells a little wider than they were historically, we think we're gonna see some really positive incremental benefit from well delivery in those areas. I think we'll look to drill those a little longer, a little wider. You know, it is gonna require some re-spacing on that program. I suspect you'll see some benefit from that in 2025. But how it works out for the full year program, you know, we're just putting that plan together now, as we're looking at developing that a little bit differently than it has been, has been done historically. But the great news is, we think, we see a lot of opportunity there, and feel really good about where we're at and how the asset's delivering. Okay. You still feel pretty good about your 14-15 kind of pro forma and for $150-$155 oil? Does that still make sense? So, you know, we've talked for a long time about. We thought we were getting about, you know, at least 140% of a two-mile well with a three mi well. So 80%, 80% of that third mi lateral of the last lateral contributing. You know, what we intend to come out with this, we're still getting some final data in now. I think in our next call, you'll probably hear us talk a little bit more definitively on what we're seeing. What I'll say is that, you know, we're really pleased on that contribution of the third mi. We went in anticipating that we were being, you know, slightly conservative on the recovery we were getting in that third mi because we wanted to be to ensure that we were underwriting the program appropriately. And, you know, as we've been able to observe now for, you know, in some cases, a couple of years' performance across those areas, we're feeling really good about what we're seeing, but we're gonna talk more definitively about that on our next call. Okay. And as my follow-up question, you know, obviously, you've had the, you know, Enerplus asset for, you know, a month or so now, and I think you've already gotten on some of those, you know, locations and drilled the pads. Can you talk about, like, what you're seeing in terms of improvement that you're able to so far see on the combined assets? And, you know, both on the, you know, relative to the prior Enerplus performance, but also, you know, are there things, you know, what specific things have you adopted on the Chord to assets so far, at least what you're seeing, that could improve what you all are doing as well? Yeah, I'm gonna ask Darrin to, to weigh in on that, but I'll just maybe, tee him up and hopefully not steal his thunder by saying, we have—you know, we really have gone into this with an, with an approach of, let's, let's ensure we're getting the full leverage out of this transaction, and so let's take the best practice we're, we're seeing, regardless of legacy organization. So we are seeing some, some Enerplus practices move forward, as well as a lot of good core, you know, legacy core practices move forward. And we're already seeing some benefits on that on both the drilling and completion side. So I'll turn it over to Darrin. Yeah, Scott, if you look at slide 11, left-hand side, what we're showing here is we've seen a 16% improvement in cycle times on drilling since we've closed the acquisition, just a couple of months ago on the Enerplus assets. And so we picked up two rigs as part of the combination, and those rigs continued to drill on that legacy Enerplus acreage. So just immediately overnight, we've been able to drive down those cycle times. Then, in the middle panel there, we're showing you as we're adopting Enerplus' simulfrac innovation, the way they implement their frac program, we'll be going from our legacy zipper program to more of a simulfrac program, and we're expecting to be able to put 40% more barrels on the ground every day that our frac crews are pumping. So, those are a couple of items we're looking at. Another one on the facility front. Chord uses a prefab design that we'll use across all of our acreage going forward, and there'll be significant cost savings there as well. So those are three items that come to mind immediately. Yeah, and just the relative improvement you're seeing there, is that what's contemplated in the $200 million of synergies? Or, you know, are you, or do some of those data points that you're showing us there, are those already incremental to the $200 million in synergies? They're all, they're all part of that $200 million basket. They're giving us confidence, so obviously, that we'll, we'll be able to exceed that, that $200 million number. Thank you. Thanks, Neal. Oh, thanks, Scott. Your next question comes from Neal Dingmann. Please go ahead. Your line is open. Good morning, guys. Thanks for the time. Danny, like, like, much for you or Darrin or the guys, something you were just hitting on. I'm just wondering on, what, what type of changes, I guess, when it comes to the D&C, you, you definitely continue to see some really notable improvements. So I'm just wondering, besides the extended lateral that you were just talking about, what other type of changes are resulting in these, these improvements? Is it, is it just spacing, or maybe if you all can just highlight some of these, and, you know, what do you think the results could be even for further, you know, return upside? So, you know, I think the, if we're talking about, the things that are driving improvement here, I mean, the, the two biggest things that are driving the improvement we've seen relative to call it, historical programs, would be, the wider spacing and the longer laterals, and we've got, we've got a lot of material in the deck, about that. You know, I would say there's always going to be, in addition to that, continuous improvement, just within your drilling and completions, organization. We, we learned what completion practices, work better, how we're able to better get all our proppant down without, you know, screening out, how we can better stay in formation from drilling, how we can improve cycle times. And so you've got this continuous improvement aspect that overlays all of that. But this, this move to wider spacing and, and longer laterals really are sort of, you know, we've used this phrase, jumping S-curves before. Those are really the two big jump the S-curve sorts—sort of opportunities for us. As we look forward, I think, folks are aware that we're planning to, to spud some four-mile laterals as well, as we get toward, the latter part of this year and into next year. And so that's really a great opportunity for us to continue to advance our practice of drilling longer, drilling longer laterals, which we just think is a far more efficient way to drain the resource. If you think about it, that incremental foot that you drill theoretically is the most efficient foot you drill, because you're able to leverage all of the fixed costs of the vertical portion of the well, all of the roads, all of the facility infrastructure, all of your midstream connections. And so it's just, it's a great way to improve capital efficiency of the program. So I think that's the next biggest sort of big thing for us to come, but maybe I'll ask Darrin to opine a little as well. Yeah, I think the way we think about the four-mile laterals, Neal, you know, we're not really thinking today that we'll convert all of our three mi DSUs to four mi DSUs. We're more thinking about those two mi DSUs that have higher supply costs. How can we convert two, two mi DSUs into a four mi DSU and really drive down the supply costs, and then, hopefully, see comparable economics to the three-mile wells? And over time, as we get efficient at that, you know our team's gonna get really good at drilling and executing four mi wells at some point in the future. It may make sense, if their economics are better than three-mile wells, then we'll really go back to the portfolio and inventory and see how do we really expand four-mile laterals across the entire portfolio? Great. Great details, guys. And then just a second question on maintenance capital. No question, you all continue to do a great job of doing more with less, and I'm just wondering, you mentioned dropping down into the one spread. Is that on a go forward? Or I guess y ou know, maybe asked another way, you know, how do you think about the maintenance plan going forward on a D&C? Because you guys have really taken some nice efficiencies there. I think if you look at the sort of pro forma early in the year, the combined rig count was around six, and the combined crew count was around three. What we saw is in the beginning of the year, we had some really good performance, really at both legacy organizations, and we had a fairly mild winter, and we got a lot more done early in the year than what we had originally modeled. And so, you know, we've said many times, we're about generating strong and sustainable free cash flow. We're not about chasing production growth. And so had we stayed at the sort of three crew count, we were gonna really drive some production growth through the system, but also outspend our capital, and that's not what that's not the type of plan that we're trying to execute here. So we dialed the program back. We brought it down to one crew, to really pull back on some of those capital expenditures. Obviously, that has sort of a near-term and a longer-term impact on production, but we still feel very good about our volumes, obviously, with raising our oil volumes and our total volumes for the year. So we thought we were in a good spot. We pulled back on capital by dropping that crew. We'll pick a crew up as we get, you know, we'll march that back up as we move forward, so you'll see that crew count increase, re-increase as we get back toward the end of the year. As I mentioned in my prepared remarks, you know, sort of late summer, late fall, we'll pick that back up. On an ongoing basis, I would say that six and three is probably a good base level to have. You know, it's gonna be our intent to try and drive below those numbers to get to, call it, five with two crews and a swing crew. At any one given point in time, you may see that fluctuate a little bit, just given the sort of vagaries of the program. As winter weather going on, do we have good, sort of, you know, good weather opportunities where we can make good production? But, you know, $6.3 would have been the pro forma. We're gonna try to, with synergies and with efficiency gains, we, you know, it's gonna be our goal to push it lower than that amount on a, sort of, call it, an average basis as we move forward. Well said. Thanks, Danny. Thank you. And your next question comes from David Deckelbaum of TD Cowen. Please go ahead. Your line is open. Hey, Danny, Michael, Richard. Thanks for taking my question today. I was curious, just again, going back to the synergy slide, particularly around downtime. If that's something, Obviously, you've already seen a huge progression with core legacy operations. As you use some of your own practices on the Enerplus production or assets, is that something that's already baked into the synergies in terms of capital costs, or could that be something that's a tailwind for sort of base decline moderation? Yeah, generally, we've baked it into our synergy expectations going forward. We like what we see, and again, giving us confidence that we say 200+ for a reason. Every day we dig into it with the new teams, we're excited with what we see and the opportunities ahead of us. Yeah, I think you heard us, David, on the Oasis merger combination, talk a lot about tailing in with resin-coated sand. That's just something that's super helpful for helping the ESP runtime go longer, and that's been something that you saw play out in the performance over the past couple of years before this new transaction. So we think that same playbook is applicable to this, and we'll see that, we'll see that flow through once we start, you know, getting the completions done on those, those wells. That'll flow through to runtime and, and LOE and, you know, and the management on that front. So it's that type of thing that's gonna, you know, gonna be part and parcel with the, you know, the, the work that we're gonna do to drive better performance on downtime. Thanks, Richard. My follow-up really is just on the extended laterals. I think, you know, you all highlighted now that pro forma, like 40% of the acreage is amenable to extended laterals. I know Enerplus came in with about 10% extended laterals in the inventory. As you think about extending laterals on Enerplus's acreage, should we think of it as next year? Do you foresee incremental land spend, or should this just all be with re-permitting and sort of redesigning how you're treating the leases and development? Yeah, I think generally speaking, it's going to be more the latter than the former. There's always a blocking and tackling program that's out in front of the rigs, looking for us to pick up incremental acreage in front of the rig. If we can extend longer laterals, we can, we like to do that. You know, trades are a big thing that we do as well, and so we look to trade acreage, and let offset operators core their acreage up and provide for longer laterals for their opportunities, as we do the same for ours. And so, you know, there will always be some level of land spending out in front of your rig programs. I think we don't see that really changing appreciably associated with this. It's gonna be more sort of that normal course spend that we would have anticipated and modeled, as well as just, you know, working through the geometry with the existing units that we've got and replotting that differently and developing differently than would have been done otherwise. Yeah, if I could just follow on to that, would that imply, just given the focus on efficiencies and extended laterals, that at least the 2025 program would be more heavily weighted to the cored acreage, all else equal, as you sort of move forward relative to 2026, 2027 and beyond? I think it's an issue of, really an issue around timing. And so as we look at the opportunity within the Enerplus assets to really change the development program, it takes some amount of time to replot all that and get that re-permitted. You need those out in front of your rigs, you know, by some period of time. And so, we recognize, you know, we're-- we, we do like to, maximize NPV and, and, and get into the best areas first. We recognize that's a great area. We want to get in there as quickly as possible, but we want to make sure, that we develop it in the right manner, as possible, too, to make sure that we do that as capital efficient as possible. And so it will take us some time to get that, to get that replotted. We're working toward that as, you know, as quick as we can, and again, we're gonna—we'll put more development, more information out about our specific development plans for 2025 as we get later into the year. Thanks for the color, guys. Thanks, David. Your next question comes from Doug Leggate of Wolfe Research. Please go ahead, your line is open. I'm sorry, did they say Doug Leggate? Or I think- Yes, John. Yeah, John. All right, appreciate it. Yeah, one quick couple of quick questions here. So Danny, there's been a lot of discussion about, you know, where you could see the synergies possibly improve. I guess when you look at the assets, the Enerplus assets that you now have in-house, when you were contemplating the deal, what has been the biggest surprise, and what did you not contemplate once you've had the assets in-house now? What has been the biggest surprise? You know, I would say, John, because we know the basin so well, I don't think there's been... The great thing is we've got offsetting acreage across the entire basin. We know the subsurface. We knew this asset was a great asset. You know, from an asset level perspective, I don't think we've seen anything from a subsurface perspective that is markedly surprising to us. I have been thrilled with how the teams have been working together to work through integration to make sure that, you know, we're able to fully recognize the full value of this transaction as we move forward. And so I don't know that there's been a big surprise to us. We knew this was great acreage. We understood that just because of our legacy position within the basin. And it's the great thing is, you know, I think we've seen modest upside in almost everything we've looked at, whether that be from a synergies perspective or how we think about the subsurface, what we think the wells are gonna do. And so it's just been, you know, we're really pleased with what we're seeing. Appreciate it. And then with respect to your synergy, the synergies, the $700 million of synergies that you're contemplating starting at the end of 2025, how do you think about the risk of that potentially moving forward? Could you walk us through that? Well, I think we've got, you know, we've really looked at synergies in three different categories, and we've talked about that a bit. One is just sort of the more administrative and G&A synergies, and I think that's sort of understandable and well understood. The capital synergies, really, we've looked at starting to capture those in 2025. The reality is we're probably getting some of those toward the latter part of this year, but in 2025, we think we'll get those in bulk because we'll be running a full combined program instead of really the two legacy programs, just as a result of having historic contracts in place and historic permits in place, et cetera. And so in 2025, we'll start seeing really those capital synergies pull through. We have, from an operating expense standpoint, you know, we have some of that we capture pretty early, but a lot of that we capture somewhat later, and that's why, as we've talked about this, the operating synergies are the ones that show up last. It's not because we're not interested in getting to those and we're not working on them first, but Richard gave a great example. I'll give an additional one on top of that. So we typically tail in with our wells, with resin-coated sand in the completions. This is a capital dis-synergy that's been modeled. And so all the capital synergies you see actually include this dis-synergy associated with tailing in with resin-coated, because it's a little more expensive. What we found over time is having that resin coat in the well prevents a significant amount of sand flow back into your wellbore, up into your facilities, and importantly, into your ESPs. Replacing an ESP and fixing a down ESP is tremendously expensive and tremendously disruptive to your operation. And so if you can prevent doing that, it's, it's great, and it results in real operating synergies. And so we've taken a capital dis-synergy that yields operating synergies, and we've seen this happen within the legacy Oasis program. We saw this happen when the Oasis Whiting combination occurred. We saw this happen, and we fully expect to see this again because we've proven it on multiple different occasions. So, but it takes a while for that ESP not to fail. So first, you've got to tail in with the resin, and then the ESP doesn't fail, and then you don't have to do that workover. And so, you know, that's one example. Another example is the strings we put in for our workover operations. You know, there's a different metallurgy that's been used historically that really results in lower, in a different installation practice and operating practice that results in lower failure rate moving forward. And again, this is something we've proven out through the Oasis Whiting transaction. We're gonna be implementing that on the Enerplus, but that takes time to take effect. And so, you know, we'll have the obvious operating synergies, consolidating some routes, running some more efficiently. That'll yield some operating benefits to us, but a lot of it comes from new practices, and then those new practices have to take hold and yield the benefit. And so that's why we don't model this really until the end of 2025 and into 2026. Hopefully, that, that color is helpful. That is very helpful, Danny. Thank you very much. Thanks, John. Your next question comes from Phillips Johnston of Capital One. Please go ahead. Your line is open. Hey, thanks for the time. You highlighted what a maintenance program looks like in terms of the, you know, six rigs and three crews, but can you give us a rough sense of what your annual maintenance capital is these days at sort of current low costs? Yeah, I'd say, you know, if we look at from a pro forma standpoint, the pro forma is probably around $1.5 billion for sort of the delivery that, you know, call it 150-153 thousand barrels of oil equivalent per day. And so that's, that's kind of where we're at currently. Okay, thanks for that. And then, you talked about the longer laterals supporting shallower declines. Can you give us an update on what your corporate next 12-month PDP decline rate is, just on a pro forma asset base? I think, I think I have in my notes, you know, kind of low to mid-30% range, if I'm not mistaken. And then I guess, just as a follow-up, as the mix of longer laterals kind of increases over time, what kind of impact to the rate could we see? I mean, are we talking just a, are we talking a few hundred basis points, or what, what, what sort of magnitude? Yeah, so from an overall corporate decline standpoint, I'd say we're in the low, very low thirties, if you're looking at total BOE, maybe slightly higher than that historically, from an oil perspective, but still in the low thirties there. The longer laterals, the neat thing about them is, you know, they come online about the same, well, not the same. They come on slightly higher, not 50, not 50% higher, but they come on slightly higher than what a two-mile well comes on. They stay flat for longer, and so from that just decline perspective, that's obviously beneficial. And then they do decline more shallowly than a two-mile well does. So, you know, as we get a bigger and bigger critical mass of those three mi wells, we should see some moderation in our overall corporate decline rate. But I would expect that to be, call it small, small single-digit percentages in, in decline or increment. Yeah. Okay. Thanks very much, Danny. Thanks, Phillips. Your next question comes from Paul Diamond of Citi. Please go ahead. Your line is open. Thank you all, and good morning. Thanks. Great, thanks for taking the call. Just want to touch on slide seven and eight a little bit. You guys talked about the kind of cumulative uplift you've seen from your spacing on the existing DSUs. Just want to talk about how much variability do you see in those numbers, and is do you think you're at the right number, or is there more tweaking to kind of ongoing? You know, I maybe ask Darrin to weigh in on this a little bit as well. You know, the neat thing is what we tried to demonstrate on that slide is in, you know, pretty different areas of the field, we're just seeing consistently improved performance through this upspacing, and it's almost, you know, it is, it's fairly proportional to the increased spacing that we're seeing there. Obviously, our completion practices change as we move forward as we move to these wider spacings. But just the ability to leverage and get more oil out of the ground for less upfront capital investment, obviously, is a great thing, and it's working across the field, and it's working in a fairly predictable manner. We recognize that, you know, we are on the more conservative side of this, and so as we talk about our—one of the neat things is, as we talk about our inventory, that's all predicated on this sort of very conservative look. We are looking at, you know, Enerplus had slightly tighter spacing across the basin, and we are going back and we're looking at our practices. We think what we've got is working really well, but we wanna be humble about this and recognize that there's other ways to do things, and so we're going back and looking at this spacing program. It could be that we've been slightly conservative here, and in some areas you may see us go from, you know, four-well spacing to 4.5-well spacing or maybe, maybe increase by a well per section. I don't think it'll be much more dramatic than that. But we're looking, we're looking across the program, and we wanna make sure this is optimized. And so, you know, I don't know who said it in the prepared remarks. We're a company that really values continuous improvement, so we're never gonna be satisfied with where we're at. We're always gonna be trying to get better, and, we're doing that work right now on the, on the development program. But Darrin's really in the thick of it, so I'm gonna maybe turn it over to him. Yeah, I think maybe the only thing that I would add to Danny's remarks is that, you know, when we look at inventory, we think about well spacing and what the correct spacing is to drain that DSU most optimally. But when it actually comes time to assemble the AFEs and figure out what are we actually gonna drill, when we're putting that drill schedule together, we look at every DSU in detail, you know, at really much more real time. Again, look at the cumulative production from the parent well and just make sure that, you know, we go in and dot our I's and cross our T's, and make sure that we have the optimal spacing with all the data, latest and greatest data from the most recent wells that were drilled. So it's really an iterative process that gets done initially as part of inventory, but then gets relooked at again when it comes time to put the drill schedule together. No, understood. I appreciate the clarity. Just a quick, kind of, quick follow-up around hedging. What do you guys see as kind of the right number? If I were to look forward and kind of modeling out, you know, 12 months ahead, is it—are you kind of happy with where you're at now for 25 or potentially adding some more? I guess, where do you all see the, kind of, the right number in the, the current environment? Yeah, well, the current environment is interesting, just relative to what the oil's done here, out of some of the volatility we've seen in the underlying commodity over the past few weeks. You know, generally speaking, I'd say we think we need to have a majority of our production exposed to the commodity. We think, you know, we've got to obviously have a very clean and healthy balance sheet and have a low reinvestment rate. And, you know, we've got a dividend and return on capital program that we think is very defendable down to very low commodity levels. And so we don't need to do a lot of hedging. We think some level of hedging makes sense, to put some predictability into the business. So generally, we sort of think, you know, call it 20%-40%. We build a hedge book up over eight quarters, and we try to do it pretty programmatically to take a little bit of the emotion out of hedging. We'll lean in a little more in areas and times of historically higher pricing, and we'll lean out a little bit in times of historically lower pricing. And so again, we'll always have a majority of the commodity exposed. We'll build it up over eight quarters, and the prompt quarter wouldn't would never be over about 40% hedged. Understood. Appreciate the clarity. I'll leave it there. Thanks, Paul. Your next question comes from Noah Hungness of Bank of America. Please go ahead, your line is open. Morning, everyone. I wanted to start on buybacks here. I know that the buyback window is impacted by the Enerplus deal, but I was kind of wondering how you guys are thinking about the variable dividend versus the buyback today, and maybe how that thinking has changed versus a month ago? Yeah, well, we've always thought that there's a, you know, there's room for both the variable dividend and a share repurchase. I think, you know, just given where our shares are trading currently, versus where we see the intrinsic value of our equity at a, you know, call it a conservative mid-cycle pricing, we see now as being a great opportunity to repurchase shares. But we think variable dividends are an effective way to return capital as well. It's particularly nice to have that as an outlet as well. This is a program, the 75% plus of the free cash flow we generate in the quarter, we like to true up every quarter. And so, you know, sometimes you end up with a little incremental free cash flow than what you anticipated early in the year or earlier in the quarter, so you weren't able to get all of those share repurchases done. Maybe you get surprised by good LOE or good CapEx. We've certainly seen that in the past. Or you could be in positions where you have material, non-public information, and you just can't be in the market. And so in those instances, having an outlet for with a variable dividend to ensure that we're delivering at least 75% plus of free cash flow is a good thing. So, you know, that's kind of how we think about it. As we look at the share repurchases, you know, we do try and look at that relative to intrinsic value and look at it relatively, you know, in a relative standpoint from our performance versus our peers. And so we've got a lot of different lenses that we look at this, but we think there's a place for both within our program. Awesome. Really appreciate that. And then, going over to slide nine, I noticed that the Clearbrook differentials have kind of bounced back later in 2024 here. Is that because of TMX, as the Canadian barrels have started to flow west? And is that improved differential captured in the, in the guidance? Yeah, differentials will, I think, start to improve a little bit towards the back half of the year. It's a combination of things. Early in the year, you did have basin production peaking kind of towards 1.3 million barrels in the basin. It's come off a little bit, with supply kind of coming off a little bit, with some of the refinery turnarounds getting through some of that, along with TMX coming online. I think you're seeing differentials improve a little bit towards the back half of the year. Awesome. Really appreciate it. Sure thing. Great. Thanks. Your last question comes from Oliver Huang of TPH. Please go ahead. Your line is open. Good morning, Danny, Michael, Richard, and team, and thanks for taking the questions. Just wanted to start off on the three mi laterals. Was hoping that you all might be able to comment around what changes, improvements, technologies, or modifications have been made based on initial learnings that could potentially drive better recovery factors on some of the more recent three mi laterals and those in the program going forward? Well, I'll start off, Oliver, and ask Darrin to weigh in. I think the biggest thing for us is one, you know, as you go through, anytime you practice something, you get better and better at it, and that certainly this industry has demonstrated that time and time again as we've gone through unconventional development. You know, the single biggest thing I would say is that our cleanout practices have really improved, and we've learned a ton and how to get all the way to the toe consistently and importantly do that with generally with coil tubing, which is the most cost-effective option to do that. And so, you know, we've learned a ton in the drilling space on how to get out there. We always thought that this would be not as easy in what we do, but relative to all the things that we do with three mi laterals, that would be one of the easier ones to accomplish. Again, not easy, but on a relative basis, maybe easier. You know, we feel pretty confident about our completion practices. We've certainly learned along the way, but our learnings on cleanouts have been pretty, pretty significant and have really driven some what we think are some fantastic results associated with our recoveries there. But I'll ask Darrin to maybe weigh in with some more. Yeah, you look at slide six, the upper right panel, and look at our first six months of production coming out of our more recent wells versus our peers. I mean, we're definitely leading the pack, and I think Danny hit the nail on the head. It really is a function of getting the wells cleaned out post-frack and getting them online. And I don't know if I have much else to add to that, Danny. Yeah. Oliver, I may add just a, a few things. I think it's a great question and really just a chance to celebrate the team. Over the last 18 months, you've seen, I think, us move and really be the basin leader of moving to three mi laterals. It's, I think, really changed the trajectory of kind of our inventory in the basin and how we're looking at it. So just a huge rate of change. I think it's also providing opportunities for us to improve what, on, on some of the Enerplus acreage as, as that comes about. You're seeing, I think, all facets of that move over the last 18 months. So whether it's the drilling times really getting much faster, our completion practices are getting better, and then all the, all the cleanouts that Danny and Darrin were talking about, it's really taken our productivity up. So it's super exciting, and we're excited that the team also gets the, the chance to kind of show that again with these four mi laterals. I think that's just a massive opportunity. We've been leaning into the three mi laterals. I would say today that it seems almost more kind of the norm for us to do three mi laterals versus where we were 18 months ago. And we're hopeful that, you know, the team can continue to show that progress on the four mi laterals and, and make that more of a standard going forward. Perfect. That's super helpful color. And maybe just a quick follow-up. Just wanted to kind of ask on slide 11, the downtime improvement slide. Does a great job to show the magnitude of potential that should be relatively low-hanging fruit to capture. Assume that a lot of this will get captured closer to that late 2025, early 2026 timeframe to align with the LOE commentary on synergies. But just wanted to kind of confirm how this potential uplift might be contemplated in your $200 million plus target. Is that already in there, or is that potential upside? Yeah, it's already contemplated in how we're thinking about the synergies and the $200 million plus. Probably, the one comment I would add to Danny's earlier remarks is that he hit the nail on the head. Many of these, we're gonna see the improvements late 2025, perhaps even into 2026, when it comes to downtime. However, one that we might see sooner is, when a well goes down, Chord historically gets on that well very quickly, and relative to what Enerplus was doing, we were getting on the wells in about half the time. And so that's something that we should be able to do right away. We've increased our workover account, and we're getting all the workovers into the queue, and that is one synergy relative to downtime that we should be able to capture quicker. Okay, perfect. Thanks for the time, guys. Thank you. Thank you. There are no further questions at this time. I'd now like to turn the call back over to Danny Brown, CEO, for closing comments. Well, thank you, Matthew. So to close out, 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 wanna 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. Ladies and gentlemen, this concludes today's conference. We thank you for participating and ask that you please disconnect your lines.