Chord Energy Corporation (NASDAQ:CHRD) Q2 2024 Earnings Call Transcript

Chord Energy Corporation (NASDAQ:CHRD) Q2 2024 Earnings Call Transcript August 8, 2024

Operator: Good morning, ladies and gentlemen, and welcome to the Chord Energy Second Quarter 2024 Earnings Conference Call. [Operator Instructions]. 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.

Bob Bakanauskas: 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 our call. I’m joined today by Danny Brown, our CEO; Michael Lou, our Chief Strategy and Commercial Officer; Darren Henke, our COO; and Richard Robuck our CFO, as well as other members of the team. Please be advised that our remarks, including the answers to your questions, include statements that we believe to be forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently disclosed in our earnings releases and conference calls.

Those risks include, among others, matters that we have described in our earnings releases, as well as 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 releases and on our website. We may also reference our current investor presentation, which you can find on our website. And with that, I’ll turn the call over to our CEO, Danny Brown.

Danny Brown: 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 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 the 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’ 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 year due to strong performance and a fairly mild winter. This resulted in volumes and capital above our original expectations early in the year. And 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 one frac crew versus three 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, but 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.

And 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 31. 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 Cord can enhance returns on these assets by applying techniques it has developed over the past several years, including longer laterals, optimized spacing 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 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, if any major onshore Lower 48 basin, which supports strong margins and impressive returns. Second, with our footprint basically extending across the entirety of 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 sharp 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 and 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 core 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.

Darrin Henke: Thanks, Danny. We had a solid quarter on the operations front as 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 a leader in three-mile lateral development. Slide 6 on the bottom left shows Chord’s longer 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-frac 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 base forecast, we currently model 3-mile wedge wells delivering approximately 40% more EUR for 20% to 25% more capital. It’s likely that we’re getting than that 40% uplift, especially since the team has improved the coiled tubing cleanout process, whereby Chord routinely reaches TD on most wells. We expect to formally update the market on our third 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 7. The chart on the upper right shows Chord’s average spacing across the basin is wider than other operators. This upspacing has helped keep the clients 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 Enbridge which assesses Chord’s widely spaced well performance versus those in enabling 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 8 shows core success with wider spacing across the entire basin. Again, Chord is draining most, if not all, the DSU with fewer wells and materially less capital than our peers. Board continues to evaluate opportunities maximize capital efficiency and continually analyzes the merits of removing or adding wells across our position. Just a couple of 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. Ford is the leader in drilling times in the Williston Basin and by applying Chord’s drilling techniques, we’ve 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 same frac completions that Enerplus used extensively. Finally, I wanted to highlight our progress in reducing downtime over the past 12 to 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 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.

Richard Robuck: 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 Enerplus standalone financials. Certain reclassifications have been made in the historical presentation of Enerplus’ 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’ 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% of our midpoint guidance and total volumes were about 2% above [Technical Difficulty].

Operator: Ladies and gentlemen, please stand by. We are experiencing technical difficulty and the presentation will resume shortly. Thank you. [Technical Difficulty]

Richard Robuck: This is Richard Robuck, again. I apologize for the interruption, a little technical difficulty on our end, but I’m going to kick back up where I think where we lost you. So we were talking about WTI realizations and we were noting where were versus WTI for our differentials at $1.71 in the second quarter, and we expect that to improve in the second half of 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, realization should also improve quickly in environments where gas prices rise. Turning to costs. LOE was $9.37 per boe in the second quarter which on a 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 in the second quarter, which we expect to come down a bit 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, and 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 $0.065 per Mcf from $0.1423 previously, which is related to trailing gas prices. Second half cash taxes are expected to be 6% to 12% of adjusted EBITDA, which is down from our original expectations for the second half, cash taxes of 8% to 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 30, Chord had $575 million drawn on its $1.5 billion credit facility, liquidity as of June 30 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 at June 30, consistent with expectations that we set out in May when we announced the transaction closing. Subsequent to the quarter, quarter paid 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.

Q&A Session

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. [Operator Instructions] And your first question comes from Scott Hanold of RBC. Please go ahead. Your line is open.

Scott Hanold: Hey. Thanks all. I have a question on — it seems like you remain pretty confident in your 3-mile EURs with your with your crosser basin 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 how much of that is being contemplated on, say, core legacy assets versus Enerplus and you going be able to quickly reoriented the lateral length and the spacing on some of the ERF acreage. So we’ll see some of that hit the ground running as you get into 2025?

Danny Brown : Thanks, Scott. This is Danny. 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 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. And 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 in that spot. So there’s just a bit of a portfolio effect that we benefit from if spread the program out a little bit.

We do recognize the core nature of the Enerplus — the acquired Enerplus acreage position. And as we can look at particularly as we can look at maybe drilling those wells a those wells a little longer, are spacing little wider than they were historically. We think we’re going to see some really positive incremental benefit from well delivery in those areas. And so I think we’ll look to drill those a little longer, a little wider. It is going to require some respacing on that program. I suspect you’ll see some benefit from that in 2025, but how it works out for the full year program. We’re just putting that plan together now as we’re looking at developing that a little bit differently than it has been done historically. But the great news is we see a lot of opportunity there and feel really good about where we’re at and how the asset is delivering.

Scott Hanold: Okay. And you still feel pretty good about your [indiscernible] kind of pro forma for 150 to 155. Does that still make sense?

Danny Brown : So we’ve talked for a long time about we thought we were getting about 100 — at least 140% of a 2-mile well with a 3-mile well. So 80% of that 3-mile lateral of the last lateral contributing. What we intend to come out with this, we’re still getting some final data. And 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 we’re really pleased on that contribution of the 3-mile we went in anticipating that we were being slightly conservative on the recovery we were getting in that 3-mile because we wanted to be — to ensure that we were underwriting the program appropriately. And as we’ve been able to observe now for, in some cases, a couple of years’ performance across those areas, we’re feeling really good about what we’re seeing. But we’re going to talk more definitively about that on our next call.

Scott Hanold: Okay. And as my follow-up question, obviously, you’ve had the Enerplus asset for month or so now. And I think you’ve already gotten on some of those 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 on the combined assets? And both the — relative to prior Enerplus performance, but also are there things — what specific things have you adopted on the core assets. So far at least what you’re seeing that could improve what you all are doing as well.

Danny Brown : Yes, I’m going to ask Darrin to weigh in on that, but I’ll just maybe team up and hopefully not steal as thunder by saying we have — we really have gone into this with an approach of let’s ensure we’re getting the full leverage out of this transaction. And so let’s take the best practices we’re seeing regardless of legacy organizations. So we are some Enerplus practices move forward as well as a lot of good Chord — legacy Chord 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.

Darrin Henke : Yes, 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 continue 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 simul-frac innovation the way they implement their frac program will be going from our legacy zipper program to more of a final frac 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, or 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 the three items that come to mind immediately.

Scott Hanold: Yes. And just the relative improvement you’re seeing there, is that what’s contemplated in the $200 million of synergies? Or are you — do some of those data points that you’re showing us there, are those already incremental to the $200 million synergies?

Darrin Henke: They’re all part of that $200 million basket. They’re giving us confidence. So obviously, that we’ll be able to exceed that $200 million number.

Scott Hanold: Thank you.

Bob Bakanauskas: Thanks Scott.

Operator: And your next question comes from Neal Dingmann. Please go ahead. Your line is open.

Neal Dingmann: Good morning, guys. Thanks. Danny — some you and Darrin and the guys, something you were just hitting on. I’m just wondering on what type of changes, I guess when it comes to the D&C definitely, continue to see some really notable improvements. So I’m just wondering besides the extended laterals that you were just talking about? What other type of changes are resulting in these improvements? Is it just spacing or maybe if you all could just highlight some of these? And what do you think the results could be even further return upside.

Danny Brown: So, I think if we’re talking about the things that are driving improvement here. I mean, 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 a lot of material in the deck about that. I would say there’s always going to be, in addition to that continuous improvement just within your drilling and completions organization. We learned what completion practices work better, how we’re able to better get all our profit down without 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 move to wider spacing and longer laterals really are sort of — we’ve used this phrase jumping S curves before.

Those are really the two big jump S curve sort of opportunities for us. As we look forward, I think folks are aware that we’re planning 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 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 drilled because you’re able to leverage all of the fixed cost of the vertical portion of the well, all 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.

Darrin Henke: Yes. I think the way we think about the 4-mile laterals, Neal, we’re not really thinking today that we’ll convert all of our 3-mile DSUs to 4-mile DSUs. We’re more thinking about those 2-mile DSUs that have higher supply costs, how can we convert 2-mile DSUs into a 4-mile DSU and really drive down the supply costs and then hopefully, see comparable economics to the 3-mile wells and over time, as we get efficient at that, our team is going to get really good at drilling and executing 4-mile wells at some point in the future. It may make sense if their economics are better than 3-mile wells, and we’ll really go back to the portfolio and inventory and see how do we really expand 4-mile laterals across the entire portfolio.

Neal Dingmann: 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 drop Darrin sort of one spread. Is that on a go forward? Or I guess maybe asked another way, how do you think about the maintenance plan going forward on E&C because you guys have really taken some nice efficiencies there.

Darrin Henke: I think if you look at the sort of pro forma early in the year, the combined rig count was around 6 and the combined crew count was around 3. 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 — and 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 going to really — we were going to drive some production growth through the system, but also outspend our capital and that 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 are in a good spot. We pulled back on capital by dropping that crew. We’ll pick a crew up as we get — we’ll go — we’ll march that back up as we move forward. So you’ll see that crew count increase. Reincrease as we get back toward the end of year. And as I mentioned in my prepared remarks, sort of late summer, late fall, we’ll pick that back up. On an ongoing basis, I would say that 6 and 3 is probably a good base level to have.

It’s going to be our intent to try and drive below those numbers to get to call it, 5 with 2 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 good weather opportunities where can make we can make good production. But 6 and 3 would have been the pro forma. We’re going to try to — with synergies and with efficiency gains, we — it’s going to be our goal to push it lower than that amount on a sort of, call it, an average basis as we move forward.

Neal Dingmann: Well said. Thanks, Darrin.

Operator: Thank you. And your next question comes from David Deckelbaum of TD Cowen. Please go ahead. Your line is open.

David Deckelbaum: 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 cost? Or could that be something that’s a tailwind for sort of base decline moderation?

Darrin Henke: Yes. We’ve baked it into our — generally, we have baked it into our synergy expectations going forward. We like what we see and again, giving us confidence that we say 200 plus 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.

Danny Brown: I think you heard us, David, on the Oasis wining combination, talk a lot about tailing in with resin-coated sand. That’s just something that’s super helpful for helping the ESP run time 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 flow through once we start getting the completions done on those wells that that will flow through to run time and in LOE and management on front. So, it’s that type of thing that’s going to be part and parcel with the work that we’re going to do to drive better performance on downtime.

David Deckelbaum: Thanks. My follow-up really is just on the extended laterals. I think 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’ acreage, should we think of it as next year, do you foresee incremental land spend? Or should this just all be with repermitting and sort of redesigning how you’re treating the leases and development?

Richard Robuck: Yes. 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 bid, if we can extend longer laterals, we can — we like to do that. Trades are a big thing that we do as well. And so we look at trade acreage and let offset operators core their acreage up and provide for longer laterals for their — for their opportunities as we do the same for hours. And so there could be — there will always — there’s always 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 going to be more sort of that normal course spend that we would have anticipated and modeled as well as the — just working through the geometry with the existing units that we’ve got and replanting that differently and developing differently than would have been done otherwise.

David Deckelbaum: If I could just follow on to that. Would that imply just given the focus on efficiencies and the extended laterals that at least the 25 program would be more heavily weighted to the cohort acreage all else equal, as you sort of move forward relative to ’26, ’27 and beyond?

Richard Robuck: 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 replated all that and get that re-permitted, you need those out in front of your rigs by some period of time. And so we recognize we’re — we do like to maximize NPV 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 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 replated, we’re working towards that as quick as we can. And again, we’re going to put — we’ll put more development — more information out about our specific development plans for 2025 as we get later into the year.

David Deckelbaum: Thanks for the color guys.

Richard Robuck: Thanks, David.

Operator: And your next question comes from John Abbott of Wolfe Research. Please go ahead. Your line is open.

John Abbott: I’m sorry, did they say, John Abbott?

Richard Robuck: Yeah, John.

John Abbott: Yeah. One quick — a couple of quick questions here. So Danny, there’s been a lot of discussion about 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?

Danny Brown: 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. 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 this is — 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, 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 going to do. And so it’s just been — we’re really pleased with what we’re seeing.

John Abbott: Appreciate. And then with respect to your synergies, the $700 million of synergies that you’re contemplating starting at end of 2025. What is — how do you think about the risk of that potentially moving forward? Could you walk us through that?

Danny Brown: Well, I think we’ve got — we really look 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 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 both 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.

From an operating expense standpoint, we have some of that, 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 well on top of that. So we have — we typically tail in with our wells with resin-coated sand and the completions. This is a capital dissynergy that’s been modeled. And so all the capital synergies you see actually include this dissynergy associated with tailing in with resin coat, 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 it down ESP is tremendously expensive and tremendously disruptive to your operation.

And so if you can prevent doing that, it’s great and it results in real operating synergies. And so we’ve taken a capital dis-synergy that relates to — that yields operating synergies. And we’ve seen this happen within the legacy Oasis program. We saw this happen when the Oasis lighting combination occurred. We saw this happen and we’re — we fully expect to see this again because we’ve proven it on multiple different occasions. So that operate — but it takes a while for that ESP not to fail. So first, you’ve got a tail in with the resin and then the ESP doesn’t fail and then you don’t have do that work over. And so that’s one example. Another example is the strings we put in for our workover operations, 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 going to be implementing that on the Enerplus, but that takes time to take effect. And so we’ll have the obvious operating synergies, consolidating some routes, running some more efficiently. That will 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 then to 2026. Hopefully, that color is helpful.

John Abbott: That is very helpful, Danny. Thank you very much.

Danny Brown: Thanks, John.

Operator: Your next question comes from Phillips Johnston of Capital One. Please go ahead. Your line is open.

Phillips Johnston: Hey. Thanks for the time. You’ve highlighted what a maintenance program looks like in terms of the 6 rigs and 3 crews. But can you give us a rough sense of what your annual maintenance capital is these days at sort of current low cost?

Richard Robuck: Yeah. I’d say if you look at from a pro forma standpoint, the pro forma is probably around $1.5 billion for sort of the delivery that call it, 150,000, 152,000, 153,000 barrels of oil equivalent per day. And so that’s kind where we’re at currently.

Phillips Johnston: Okay. Thanks for that. And then you talked about the longer lateral supporting shallower declines. Can you give us an update on what your corporate next 12-month PDP decline rate is just on the pro forma asset base. I think had the now kind of low to mid-30% range, if I’m not mistaken. And then I guess just as a follow-up, has the mix of lumber laterals kind of increases over time, what kind of impact to the rate could we see? I mean are we talking just — are we talking a few hundred basis points? Or what sort of magnitude?

Danny Brown: Yeah. So from an overall corporate decline standpoint, I’d say we’re in the low — very low 30s if you’re looking at total BOE, maybe slightly higher than that historically from an oil perspective, but still in the low 30s there. The longer laterals, the neat thing about them is they come they come online about the same, they come out slightly higher, not 50% higher, but on slightly higher than what a 2-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 2-mile well does. And so as we get a bigger and bigger critical mass of those 3-mile wells, we should see some moderation in our overall corporate decline rate. And I — but I would expect that to be, call it, small single-digit percentages in decline or ResMed.

Phillips Johnston: Yeah. Okay. Thanks very much, Danny.

Danny Brown: Thanks, Phillips.

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

Paul Diamond: Thank you all and good morning. Thanks for taking the call. I just want to touch on Slide 7 and 8 a little bit. You guys talked about the kind of the cumulative up that you’re seeing from your spacing on the existing DSUs. Just want to talk about how much variability do you see in those numbers? And do you think you’re at the right number? Or is there more tweaking to kind of ongoing?

Danny Brown: I’ll maybe ask Darrin to weigh in on this a little bit as well. The neat thing is, is what we tried to demonstrate on that slide is in pretty different areas of the field, we’re just seeing consistently improved performance through this upspacing and it’s almost — it’s fairly proportional to the increased spacing that we’re seeing. There — obviously our completion practices change 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 are currently — we recognize that we are on the more conservative side of this.

And so as we talk about our — one of the new things is as we talk about our inventory, that’s all predicated on this sort of very conservative look. We are looking at — 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 want to be humble about this and recognize that there’s other ways to do things. And so we’re going back and looking at the spacing program. It could be that we’ve been slightly conservative here. And in some areas, you may see us go from for well spacing, the 4.5 well spacing or may be increased by a well per section. I don’t think it will be much more dramatic than that, but we’re looking across the program and we want to make sure this is optimized.

And so I don’t know who said it in the prepared remarks, we’re a company that really values continuous improvement. So, we’re never going to be satisfied with where we’re at. We’re always going to be trying to get better. And we’re doing that work right now on the development program. But Darrin is really in the thick of it. So I’m going to maybe to maybe turn it over him.

Darrin Henke: Yes, I think the only thing that I would add to Danny’s remarks is that 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 going to drill when we’re putting that drill schedule together, we look at every DSU in detail at really much more real-time. Again, look at the cumulative production from the parent wells and just make sure that we go in and dot our Is and cross our Ts 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.

Paul Diamond: 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 in kind of modeling out 12 months out? Is it — are you kind of happy with where you’re at now for 2025 or potentially adding some more? I guess where do you all see the kind of the right number in the current environment?

Danny Brown: Yes. Well, the current environment is interesting just relative to what the oil has done here of some of the volatility we’ve seen in the underlying commodity over the past few weeks. Generally speaking, I’d say we think we need to have a majority of our production exposed to the commodity. We think we’ve got to obviously have a very clean and healthy balance sheet and have a low reinvestment rate. And we’ve got a dividend and return of 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 within into the business. And so generally, we sort of think, call it, 20% to 40%.

We build a hedge book over eight quarters, and 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. We’ll 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 would never be over about 40% hedged.

Paul Diamond: Understood. Appreciate the color. I’ll leave it there.

Danny Brown: Thanks, Paul.

Operator: And your next question comes from Noah Hungness of Bank of America. Please go ahead your line is open.

Noah Hungness: Good morning, everyone. I wanted to start on buybacks here. I know the buyback window is impacted by the Enerplus deal, but I was kind of wondering how you guys are thinking about be variable dividend versus the buyback today and maybe how that thinking has changed versus a month ago?

Michael Lou: Yeah. Well, we’ve always thought that there’s room for both the variable dividend and the share repurchase. I think just given where the where our shares are trading currently versus where we see the intrinsic value of our equity at a, 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 generated in quarter, we like to true up every quarter. And so 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 repurchase is 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 nonpublic information and you just can’t be in the market. And so in those instances, having an outlook with a variable dividend to ensure that we’re delivering at least 75% plus of free cash flow is a good thing. So that’s kind of how we think about it. As we look at the share repurchase we do try and look at that relative to intrinsic value and look at it 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 at, but we think there’s a place for both within our program.

Noah Hungness: Awesome. I appreciate that. And then going over to slide 9. I noticed that the Clearbook differentials have kind of bounced back later in 2024 here. Is that because TMX as the Canadian barrels have started to flow west? And is that improved differential captured in the guidance?

Michael Lou: Yes. 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 the 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. .

Noah Hungness: Awesome. Really appreciate it.

Michael Lou: Thanks.

Operator: And your last question comes from Oliver Wang of TPH. Please go ahead. Your line is open.

Unidentified Analyst: Good morning, Danny, Michael, Richard and team. And thanks for taking the questions. Just wanted to start-off on the 3-mile laterals. I 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 3-mile laterals and those in the program going forward? .

Danny Brown: Well, I’ll start off, Oliver, and ask Darrin to weigh in. I think the biggest thing for us is, one, as you go through any time 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. 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 importantly, do that with — generally with coil tubing, which is the most cost-effective option to do that. And so we’ve learned a ton in the drilling space on how to get out there. We always thought that this would be — nothing is easy in what we do, but relative to all the things that we do with 3-miles 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 along the way, but our learnings on clean outs 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.

Darrin Henke: Yes. You look at slide 6, 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 getting the wells cleaned out post frac and getting them online. And I don’t know if I have much else to add to that, Danny.

Michael Lou: Oliver, I may add just 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 3-mile 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 some of the Enerplus acreage 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 practice is getting better and then all the cleanouts that Danny and Darren were talking about, it’s really taking our productivity up.

So super exciting, and we’re excited that the team also gets the chance to kind of show that again with these 4-mile laterals, I think that’s just a massive opportunity. We’ve been leaning into the 3-mile laterals I would say today, it seems almost more kind of the norm for us to do 3-mile laterals versus where we were 18 months ago, and we’re hopeful that the team can continue to show that progress on the 4-mile laterals and make that more of a standard going forward.

Unidentified Analyst: Perfect. That’s super helpful color. And maybe just quick follow-up. Just wanted to kind of ask on Slide 11, the downtime improvement slide, does a great job to show magnitude of potential that should be relatively low-hanging fruit to capture. I assume that a lot of this will get captured closer to that late 2025, early 2026 time frame to aligned 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?

Darrin Henke : Yes, it’s already contemplated in how we’re thinking about the synergies and the $200 million plus. And some — probably the 1 comment I would add to Danny’s earlier remarks is that he hit the nail on the head, many of those we’re going to see the improvements late 2025, perhaps even in the 2026 when it comes to downtime. However, 1 that we might see sooner is we — when a well goes down, cord 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. So that’s something that we should be able to do right away. We’ve increased our workover rig count, and we’re getting all the workovers into the queue, and that is one synergy on the — relative to downtime that we should be able to capture quicker.

Unidentified Analyst: Okay. Perfect. Thanks for the time guys.

Darrin Henke : Thank you.

Operator: Thank you. And — 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.

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

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