Oliver [LastName]: clarifying the tow contribution with tracers on these four-mile laterals, but just as you all get more data and a greater sample set, is there a point in time or some sort of quantitative benchmark that we should be aware of where you all would kind of revisit and start to assume maybe a greater than the 80% contribution on the last mile of the Wells lateral if the data were to be supportive of it?
Danny Brown: I think the answer to that, Oliver, is yes. Just like with the three-mile laterals, you know, after we got enough production history, we came out and said we were no longer underwriting that last mile at 80. We were moving that up to 100% because we were seeing that through the production data. I think it would be sort of a similar case from a four-mile lateral standpoint. So a little too early for us to say that right now, but we're continuing to monitor our production. And given, you know, if we're If we continue to see things look positively, hopefully we'll come out with an update at some point in the future indicating that we're getting more from that last mile than we're currently underwriting.
Conference Participant: Makes sense. Thanks for the time. Thanks, Oliver.
Natasha: Your next question comes from Philip Junkworth with BMO Capital Markets. Please go ahead.
Jack Kinnergan: Hi, this is Jack Kinnergan on for Phil. Just hoping you could touch on crude differentials a little bit. I think I have a decent understanding of the near-term premium to WTI, but can you help us understand what the second half might look like and why you could still price barrels above WTI at that point?
Michael [LastName]: Yeah, Jack, good question. Obviously, over the end of the first quarter and into the second quarter, you're seeing stronger differentials in the basin. Some of that is, as you think about Brent TI differentials, they've widened. A lot of our barrels get to the coastal markets, and so you're seeing very strong differentials in basin. A lot of that's going to depend on kind of how the broader global markets act, but we think that it certainly will last through the second quarter and maybe beyond into the second half of it.
Conference Participant: Understood. Thank you.
Jack Kinnergan: And you touched on your capital plans for the balance of the year a little bit, but just seeing the oil uplift in 1Q and the better 2Q and 3Q guide is trying to get into the sense of the 4Q dip and just understanding if there's a case for running higher activity there, filling in completion white space just to maintain operational momentum, even if it leads to some capex creep.
Danny Brown: Yeah, Phillip, I think at this point we're pretty happy with our activity levels. You know, we've got the spot crew we'll release later this year. And so, you know, we run that crew continuously until we drop it. So it's not really like we need to manage white space on a sort of in-between an existing program. It's just we'll drop that. And so I don't think there's a lot of efficiency improvement we'd pick up by pushing incremental activity through the system. So we're I think we're happy with our activity levels where they are right now. We'll continue to monitor the macro situation, but too early for us to pivot off that. We're very comfortable with where we're at now.
Conference Participant: Great. Thank you for the time.
Natasha: Your next question comes from Scott Hanold with RBC Capital Markets. Please go ahead.
Scott Hanold: Yeah, thanks. I was wondering if we can pivot to shareholder returns, you know, you all had a pretty good appetite to, you know, be pretty aggressive with buybacks getting close to 100% in past quarters, it sounds like you want to be a little bit reserved, just not to be pro cyclical. But like, when you look at your stock price today, you know, if in, you know, with oil kind of still near $100 a barrel, is this an opportunity for you to continue to be pretty assertive with buybacks and push it a little bit harder, or would you rather just wait for a much more counter-cyclical time to get that robust with buybacks?
Danny Brown: Scott, I'd kind of frame it this way. Clearly, if you look at the headline oil price, our stock is not underwriting anywhere near that level. in our opinions. And so we really like where our stock's at right now. And I think buybacks will command a, you know, are very attractive at the current levels. At some point, it may be that, you know, we see our stock price underwriting a significantly higher world price. We're not seeing that today, but we may see that at some point. At that point, we would consider tapering back on those buybacks to avoid being pro-cyclical. But I like where our shares are right now.
Scott Hanold: Okay, understood. And I guess looking at the tuning pad, could you just talk about the learnings from that? Have you seen cost reductions with that pad consistent or better than what you expected? And what does that mean for four-mile pad development moving forward?
Danny Brown: I'll let Darren address this. I'd say generally speaking, Scott, we're really happy with what we saw at the tuning. And any time you get to pad level development, you're just going to pick up efficiencies as opposed to doing one-offs. And so getting to pads is a pretty big cost improvement for us organizationally. But I'll let Darren expand. Yeah.
Darren [LastName]: So we have 12 four-mile laterals now producing. And so five of them were on the tuning pad. And We have drilled 33 four-mile laterals. And so there's tons of learnings, not only on the tuning pad, but where we've drilled other wells on other pads, four-mile wells. And we're consistently getting those wells drilled with one BHA. We recently just drilled our first hairpin with one BHA. So pretty neat accomplishment there. So the tuning was just able to put it all together on one pad. Definitely saw efficiencies across the entire pad that we'll take into the future for future pads.
Conference Participant: Learning has come in all those wells that we've done.
Darren [LastName]: As far as you asked about costs and performance, the costs were in line with what we thought we would do on that pad. The well productivity is in line with what we thought. We're very pleased with what we're seeing with our four-mile program at this time.
Conference Participant: Appreciate that. Thank you.
Natasha: You now have a question from Neil Dingman with William Blair. Please go ahead.
Neil Dingman: Morning, guys. My first question, you know, Dan, a little bit maybe more on capital allocation than, you know, what you mentioned, the prepared remarks. Specifically, you know, I know you've had – I've seen a couple guys now talk about dialing down buybacks perhaps in the turn-up cycle. Just wondering what's your thoughts? on incremental buybacks versus debt repayment for remainder of this year prices stay here?
Danny Brown: Yeah, I think, Neil, in the current environment, we think, you know, our return of capital framework provides a great framework for us to think about capital allocation. We, you know, we have based on, we listen to investors and based on a lot of investor feedback, we're not really focused on variable dividends at this point. So I think our return of capital program is really going to be made up of what we think is a pretty strong base dividend plus share repurchases. We really like the shares with where we're at right now. We do recognize that if we see elevated oil prices, some of that elevated oil price may cause us to think a little bit about is it the right time for us to be buying back aggressively shares. We've said for a long time we're not fans of pro-cyclical buybacks. That's not something we've been focused on recently. historically, but I don't think where we're at currently, that's what we're doing. We think the shares are very attractive, and they're currently commanding a significant focus from a capital allocation perspective.
Neil Dingman: Makes sense. Thank you. And then second question, maybe around slide 15, a little bit more than what you said on inventory. Specifically, you all suggest, and I agree, 10-plus years of low break-even inventory. Can you speak to, you know, maybe have the assumptions changed at all when you include maybe what level of, you know, kind of your price deck you're assuming here, you know, maybe cost around that, then, you know, maybe other things that dictate how you view the break-evens in the corresponding inventory?
Danny Brown: Yeah, so the inventory that we put out there is really sub-60 WTI inventory. And so that's really what's determining that count. And so if that if our pricing assumptions from a commodity perspective were higher than that, you know, you'd see more inventory on that from account perspective. So that's what we're assuming on that, Neil. I think if structurally, again, we get to a situation where structurally we see a longer-term higher oil price, then perhaps we would think a little differently about what our inventory position is, and you'd see more inventory flow in. But we're looking at it from a sub-60 standpoint.
Conference Participant: Great. Thank you, Dennis. Thanks, Neil.
Natasha: Your next question comes from Michael Furrow with Pickering Energy Partners. Please go ahead.
Michael Furrow: Hi, good morning. Thanks for taking our questions. Danny, I want to follow up on that last statement. You mentioned how higher oil prices would unlock some inventory that might not have been economical a few months prior. So would that change your capital allocation priorities, or would you still plan on targeting your highest return wells first?
Danny Brown: I think we would continue to focus on our highest return wells first.
Michael Furrow: Got it. That makes sense. Okay. As a follow-up, clearly some volatility this morning. It sounds like the message is clear that activity levels are unlikely to change given the current market dynamics. But what other levers can the company pull to capitalize on higher prices?
Danny Brown: Yeah, I think, you know, we say activity. Our drilling and completion activity, we don't anticipate changing. But we have flexed up on some of the very, very new term, you know, more OPEX-related opportunities. So the workovers and and some of the chemical jobs and these things that really are opportunities across our 5,000 existing wells, we are looking at that because that can deliver very, very short cycle volumes at incredibly high IRRs and profitability. And so we're looking at those types of opportunities. And you've seen us deliver some incremental volumes in the first quarter as a result of that. So we're looking at that. And then the other thing I'd say, Michael, is we continue to focus on improvement across all aspects of our business. And so that's a lever that we continue to pull and have the entire organization focused on, is how do we do better tomorrow? And we've got around 800 people who wake up every morning and come into the office trying to make tomorrow better than today from our cost structure perspective, from our productivity perspective. And so we've focused on that for a long time, and that focus continues. Because we can't control what oil price is, but we can control what our cost structure looks like. We can control how we develop the field, and so we're focused on that quite intensely. So we'll flex into those opportunities that deliver very robust and attractive short cycle, and by that I mean sort of more OPEX things that can deliver some oil next week or next month. You've seen us do that, and then we'll focus on just improving the business across the board.
Conference Participant: That's great, Keller. Thanks for your time. Thank you.
Natasha: You have a question from John Anis with Texas Capital. Please go ahead.
John Anis: Hey, good morning, all, and thanks for taking my questions. For my first one, in building off of what you just mentioned, I wanted to ask if you could provide some color on the organizational changes you've made, whether it be standing up new teams or shifting allocation of resources that have been driving the improvement in base production optimization initiatives.
Danny Brown: It's a great question, John. I think maybe one of the most significant organizational changes we've made recently is in our production engineering team, we've actually sort of bifurcated that team into those that are looking at our wells that are on ESPs, and I'd call it our high-rate wells, and having a separate team looking at the balance of our wells, which is measured in the thousands, that aren't on ESPs and delivering high rate. As would be natural, you can imagine a team that's responsible for looking after all of that, the natural focus and the appropriate focus is going to be to focus on those high rate wells, those ESP wells, because they have the biggest impact on your organization. And unfortunately, the reality is that sometimes you don't focus as much on the other wells, which still could provide meaningful value, but on a relative basis, they just don't command as much as your attention. And so we sort of recognize that dynamic going on in the organization, and we've now bifurcated that team. And so we have a group that's dedicated just to looking at these lower-producing wells, but there's a lot of them, and in aggregate, they can have a big impact into what we deliver and what our overall cost structure looks like. So we've seen success with that, and I'm really pleased with the results and the focus of that team, of both of those teams, because they're delivering great records.
John Anis: Terrific. For my follow-up, you're guiding around 40% of 2026 tills and 60% of spuds being four-mile laterals. Could you provide some color on how the four-mile spud tilt this year potentially impacts the 2027 production profile? And then is there a ceiling on the four-mile development mix given 50% of your inventory are four-mile locations and DSU geometry constraints?
Danny Brown: Yeah, well, to your point, we think about 50% of our inventory is four miles. And so I think any year you'll see us sort of, I'll call it an error bar around that 50%. Maybe some years we'll be slightly ahead and some years we'll be slightly underneath. But generally speaking, you know, I think our development programs will probably, you know, largely mirror our inventory makeup. And so that's kind of how I would characterize it. Now, because we're We're sputting, you know, 60% four miles this year. Obviously, that's going to roll into 27 from a production perspective. You know, so we've started that ramp this year, and we'll just sort of continue that into 2027.
Conference Participant: Thanks. I'll turn it back.
Natasha: Your next question comes from Phillips Johnston with Capital One. Please go ahead.
Phillips Johnston: Hey, thanks for the time. I wanted to ask you about the XTO assets. I recall you guys are in the process of re-permitting, I think, most of those wells for longer laterals. I just wanted to see where we are in that process and when we might see some of those wells come into the fray.
Danny Brown: Yeah, I think as we've worked through, clearly as we've moved into four monolaterals and looking at our spacing opportunities in the lateral links. We wanted to make sure we maximized the contribution from that asset. And so we've taken our time in doing that. And so as we look toward developing in that area, I think that's probably more of a late 27 type phenomenon. And so we might get some contribution from it in 27, but more likely going into 2028.
Phillips Johnston: Okay, sounds good. And then I'm sure you can't comment too much on this one, but what's the latest messaging regarding long-term plans for the Marcellus acreage?
Danny Brown: So I think the messaging around Marcellus really kind of remains consistent. We continue to see that as a non-core asset and have been very, you know, front foot and consistent in saying that we're looking to maximize value for our shareholders. And that would include divesting that asset. But I'd say we're not in a rush, but certainly it's non-core, and we just want to maximize value from it. In the meantime, I'd say it's got very low friction cost to us holding, and you can see from our first quarter results the significant value that asset contributed. So non-core, we want to maximize value from it. We are absolutely open to divesting it, but we want to make sure we do that in a fashion that maximizes value for shareholders.
Conference Participant: Sounds good. Thank you, Danny. Thanks, Phyllis.
Natasha: As a reminder, if you wish to ask a question, please press star 1. Your next question comes from John Edelman with Jeffrey. Please go ahead.
John Edelman: Hey, Danny and team. Appreciate you getting me on. Just a quick one for me. I heard from NAWG earlier this week, or last week, I guess, about a large Bakken package that was coming for sale. Just wanted to get your thoughts on M&A and the current elevated price environment and sort of what type of leverage are you guys kind of on an upside scenario able to kind of stretch to for the right type of inventory mix? Thanks.
Danny Brown: So I'll make some opening comments, then I'll pass it over to Michael. You know, I think from a positioning perspective, we clearly, you know, our Our footprint in the Bakken really stretching across the entirety of the basin means that any package that comes to market there, we think we could be, you know, quite competitive on. We can bring synergies to bear, I think, really like no one else can. We've got great supply chains in place. We know the subsurface quite well. And so from, you know, we're believers in consolidation, and so I think we can compete well in any process. But we will also be very disciplined. and what we do, and you'll see us, you know, you haven't seen us win every deal in the Bakken, and oftentimes that's been because, you know, the market clearing price wasn't something that we think made us a better company at the end of the day. So with those as maybe opening comments, I'll ask Michael to fill in with some more color.
Michael [LastName]: Yeah, John, I would say that usually when prices are moving very rapidly, there's a bit of a lull in terms of M&A opportunities that are out there. As you've seen elevated pricing for called two months now, I think that because of that, you're going to see some assets come to market. The big question is whether or not you're going to be able to close the gap between buyers and sellers in terms of valuations and see how that goes. As Danny mentioned, We think we're in great shape to be consolidated in Bakken, but we're going to be disciplined in the way we look at that marketplace.
Natasha: This looks like all the questions for now. So, I will turn the call over to Danny Brown, DEO, for closing remarks. Please continue.
Danny Brown: Okay, thanks, Natasha. Well, to close out, I just want to extend my sincere thank you to all of our employees who, through their hard work, have positioned us for continued success. Cord has consistently delivered results that have exceeded expectations while improving the quality and depth of our inventory and enhancing profit margins. Cord has created what we believe is a valuable and increasingly rare asset. Cord has a substantial low-decline, high oil cut production base paired with a deep inventory of highly economic, conservatively spaced, oil-weighted locations. We feel great about our competitive position and have a lot of confidence in our ability to deliver going forward. And with that, I appreciate everyone's interest and thank you for joining our call.
Natasha: Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.
