Chord Energy Corporation (CHRD) Q2 2026 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Chord Energy Second Quarter 2026 Earnings Conference Call. [Operator Instructions] This call is being recorded on Thursday, August 6, 2026. I would now like to turn the conference over to Bob Bakanauskas, Vice President of Finance. Please go ahead.

Thanks, Julie, and good morning, everyone. This is Bob Bakanauskas, and today, we are reporting second quarter 2026 financial and operational results. We are delighted to have you on the call. I'm joined today by Danny Brown, our CEO; Michael Lou, our Chief Strategy Officer and Chief Commercial Officer; Darrin Henke, our COO; 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 on our conference calls. Those risks include, among others, matters that we have described in our earnings releases as well as in our filings with the Securities and Exchange Commission, including our annual report on Form 10-K and our quarterly reports on Form 10-Q. We disclaim any obligation to update these forward-looking statements. During this conference 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.

Thanks, Bob. Good morning, everyone, and thanks for joining our call. Last night, we released our second quarter results, along with an updated investor presentation. In those documents, you'll see Chord delivered another quarter of strong operational and financial performance, which resulted in free cash flow above expectations. Execution remains solid across the organization. Oil production came in at the high end of guidance, while adjusted capital spending finished modestly below the midpoint of guidance. Additionally, we continued making progress on a number of strategic initiatives that we believe will further improve the quality of our business and enhance long-term free cash flow generation. Adjusted free cash flow for the second quarter was $414 million, exceeding expectations, and we returned 54% of this or $220 million to shareholders through a combination of our base dividend and share repurchases. With Chord's balance sheet growing to $612 million and normalized leverage declining below [ 1.5 ] turn at quarter end, targeted return of capital is expected to increase to at least 75% of adjusted free cash flow beginning in the third quarter. Stepping back and looking at the macro for a moment, we've obviously seen unusually high volatility this year and the outlook for commodity prices, particularly oil, remains uncertain. Against this backdrop, Chord will remain focused on disciplined capital allocation and driving continuous improvement through the business. And while we expect to see further volatility in the macro, we have diligently built a company that can consistently generate attractive returns across a wide range of price environments. Chord has operated a maintenance plus program for over 5 years. This approach has created a large, resilient production base with low declines supported by an efficient drilling and completions program that delivers volumes and an attractive supply cost. This approach has supported sustainable free cash flow generation and robust shareholder returns. We continue to believe this is the right approach today even as we leaned into the plus last quarter by raising our full year guide by 2,000 barrels of oil per day through our investment in an array of low-cost, short-cycle base production opportunities. Diving deeper into Chord's continuous improvement initiatives, we continue to make progress across a wide variety of areas, including driving longer laterals, improving cycle times, optimizing the production base, implementing AI and optimizing marketing contracts. As I mentioned in May, Chord is pursuing various projects to optimize its large PDP base. These activities include accelerating workovers, reducing cycle times for down wells, various chemical jobs, debottlenecking surface constraints, optimizing artificial lift through AI and a host of other projects. Success year-to-date has driven Chord's full year volume above original expectations, as I just noted. Since May, the team has broadened the scope of its chemical workover program to test multiple new opportunities. That is we are testing additional chemical treatments over a larger population of wells. We are currently assuming only limited volume upside from these initiatives as we evaluate their effectiveness, economic returns and implications for the program going forward. While these initiatives have created some near-term upward pressure on LOE, we believe expanding the program is the right step to maximize the long-term potential of the business. On the drilling and completion side, Chord continues to operate well and set new records. Transitioning the portfolio to longer laterals has been highly impactful for Chord, driving a structurally lower cost of supply and higher returns on invested capital. Since the May update, Chord has turned in line 4 additional 4-mile pads. And as of today, the company has executed 26 4-mile wells in total. Importantly, Chord continues to reach total depth on cleanouts and execution as well as early performance of the 4-mile program is in line with expectations. Chord remains on track to scale its 4-mile program through the second half of 2026 and into 2027. Looking at cycle times, year-to-date, we've seen some acceleration on the frac side, which has essentially derisked the 2026 development program by pushing volumes to the front end of the year. The team also successfully executed the basin's first trimulfrac, which we believe could further drive efficiencies in select areas by reducing completion costs while maintaining high execution quality. Additionally, Chord is benefiting from reduced facilities-related capital through equipment reuse and scalable facility design. So you can see Chord continues to make progress driving efficiencies across the business. This has resulted in higher levels of sustainable free cash flow, which in combination with our share repurchase program has driven strong growth in free cash flow per share. Slide 7 in our investor presentation highlights that free cash flow per share has grown about 30% since 2024 on normalized commodity pricing. And when using actual 2026 pricing, the growth is obviously substantially higher. That's impressive performance, but maybe even more impressive when considering we preserve the balance sheet along the way. Turning to updated guidance. We've made a few fairly minor changes. We continue to expect oil volumes to average 161,000 barrels of oil per day over the course of 2026, which is 2,000 barrels of oil per day higher than our initial outlook, largely due to investing in [indiscernible] based production. On the D&C side, due to faster cycle times, we accelerated some activity to earlier in the year, which increased first half volumes and reduced second half relative to our initial outlook. On the capital side, our outlook is essentially unchanged. Looking at the quarterly cadence, we are expecting a meaningful reduction in spending during the third quarter as we drop our second frac crew, followed by another decline in the fourth quarter. We've also updated our differential and realization outlook to reflect current market conditions. Unique market circumstances drove Bakken crude to trade at premiums to WTI during the second quarter. Currently, we're expecting that premium to fade over the course of the year. On the natural gas and NGL side, we also updated differential guidance to reflect current market conditions. Full year LOE expense was raised to $10.30 per BOE, reflecting the additional production enhancement initiatives discussed earlier. Additionally, we have also seen some higher workover costs relative to initial expectations as well as a bit higher nonoperated LOE. Expanding on these additional production enhancement opportunities, I'd like to emphasize that Chord is very focused in maximizing economic returns. If investing a small amount of incremental LOE in short-cycle opportunities today has a high probability of generating strong risk-adjusted cash flow in the future, that's exactly the type of investment we want to make. Finally, turning to our updated hedge position. You can see Chord has added some incremental hedged volumes over the next couple of years. Currently, we have approximately 38% of our second half 2026 oil volumes hedged and about 18% of 2027. So in closing, Chord remains committed to delivering affordable and reliable energy in a sustainable and responsible manner. We remain focused on the factors we can control and driving improvements across the business. And with that, Julie, we'd be happy to open the line for questions.

[Operator Instructions] Your first question comes from Bert Donnes from William Blair.

First question would just be on capital allocation. I think you pointed out that you're going to step up that free cash flow payout in the remainder of the year. I just want to make sure I understood that wording. It specifically said 3Q. Should we expect that for 3Q and 4Q going forward? Or just what is the strategy going forward on those levels?

Bert, thanks for the question. Yes, I'd say I would expect to see that in 3Q and 4Q as we move forward. As we talk about this, we've always -- we've been pretty transparent about how we think about return of capital to shareholders. And as we drop below this [ 0.5 ] turn levered on our normalized pricing basis, we've committed we'll return at least 75% back to shareholders. And so we've hit that mark. We expect to do that as we move forward. Now of course, if something happened and we saw our leverage go up, I don't anticipate that, but we'll -- we evaluate it then, but I would fully anticipate we'll be above 75% at a floor of 75% for the balance of the year.

That makes sense. So remaining flexible, but expecting over that 75%. And then maybe on the oil differentials that you mentioned in your opening remarks, -- you're starting to guide almost in parity with WTI, that's better than we've seen in prior periods. But oil is a little bit higher than a year ago. So I was just trying to understand, is that where you see it long term? Or is there upside here? And then maybe any thoughts on third-party operator activity or infrastructure capacity? Just where are we in that supply and demand balance?

Yes, Bert, Michael Lou here. Good question. I think the Bakken overall has traded kind of anywhere from a $2 negative to [ TI ] to $2 positive. We certainly saw some significant positives in the second quarter. A lot of that has to do with where we are in the basin, there's a lot of takeaway and production has been generally pretty flat. And so you're in a really good position from broad differentials in the basin. With the huge run-up in oil price in the second quarter because of the war, we saw a huge backwardation in the curve. So you saw some of that CMA roll kind of roll through to better differentials. To the extent that you see -- you continue to see higher prices in the front and a bit of a backwardated curve, I think you're going to see really tight differentials. We're not thinking that we're going to get that all through the second half. And so what you're seeing us guide to is something just below WTI, still very strong differentials in the basin. But I would say that if you saw periods where you saw the price spike in the front, you should expect differentials to continue to get better for us overall.

Your next question comes from John Abbott from Wolfe Research.

The first question is really on workovers and the chemicals that you're testing. So to start off, could you just sort of describe what your typical workover program sort of looks like? What sort of uplift that you sort of see typically from the pathways you've done your workovers? And then could you talk about the early test that you've seen on the chemicals and your -- that made you sort of expand into these other testing this wider test that you're doing? And when would you have sufficient data to potentially incorporate more of that into your oil outlook?

Great, John, this is Danny. So maybe a few comments here. So I would say from a workover perspective, our workovers really cover a whole wide variety of different activities. This could be things from ESPs going down to holes in tubing to rod repairs that need to be done. And it could also involve these -- some of these chemical treatments that we're looking at doing. And so I think it really just depends on sort of the opportunity we see on an individual well. Oftentimes, we'll have wells go down for various reasons. And so we have a whole fleet of workover rigs that work to bring those wells back online. And sometimes, we just think the wells may be producing less than optimal, and we have an opportunity maybe to improve their production. It's not that they're offline. We just think maybe they're suboptimized from a production delivery perspective. And so it really holds a whole different array of opportunities. With respect to the chemical programs, we've tried some chemical programs through the first part of the year. I'd say it's appropriate to say that we've been encouraged with what we've seen, and we're excited about some of the opportunities, and we've got incremental testing we want to do, and we want to expand that testing as we move out and move further. And so early results have been encouraging. We don't know -- ultimately, we need to see the production hang in for a little longer before we can start really hanging sort of full expectations to it and start to include that as our full volume expectations moving forward. But I'd say early results are encouraging, which is why you're seeing us expand this program -- why you're seeing us expand this program as we move forward. And as we get more information, it's going to be a little -- I think, a little bit opportunity specific -- there may be some jobs that it's quite evident that inconsistent that we see production increases and or failures where it doesn't work, and we'll be able to sort of understand what that looks like pretty quickly. Others, it may take us a little more time if we see more variability in the results. So we'll pass that along and incorporate it into our guidance as we're able to get that information and have confidence about it and move forward. And so I look a lot. I want Darrin to also have an opportunity to give any color commentary from his perspective.

Yes. Probably the only thing I'd add to what Danny said was some of the jobs we're doing, we're lowering the pumps, and we're seeing increased productivity there. As we've shown on Slide 6, you can see how we've arrested the decline on a pretty good chunk of our wells through these different opportunities. So definitely encouraged with what we've seen and stay tuned.

Appreciate it. And then your commentary about trimul, you did your first trimulfrac up there. You've talked about doing that in select about opportunities in select areas. I guess, areas -- I mean, I guess, how does that sort of relate as you sort of think about overall inventory? And given this sort of -- given this, how do you sort of think of trimulfracs sort of feeding into next year? What is the opportunity for you there in terms of you sort of think about your overall inventory going forward?

Yes, John, this is Darrin again. So we're really starting to investigate optionality around trimulfracs for next year. And it could be 25% to maybe as much as 50% of our program next year, probably 20% to 50%, somewhere in that range. We're -- it takes a lot of things to make all that work out. We're also looking at remote fracking, which would allow us to trimulfracs not only on one pad, but multiple pads perhaps at the same time. So the team was definitely encouraged with what we saw with the first trimulfracs in the basin. Efficiencies were was amazing, how nice -- how great a job the team did in standing that up and really improving the efficiency of that frac crew. And so we're excited about it. We're going to look for additional opportunities. And -- but I can't really speak to the inventory, how much of our inventory looking out over the next 10 years that we can do with trimulfrac. But next year, it could be, like say, 20% to 50%, perhaps would be the range.

Your next question comes from John Annis from Texas Capital.

For my first one, the economics on Slide 13 assume 80% contribution from the fourth mile. With 26 [ TIL'd ] and over 50 drilled, how many have 6-plus months of production? And is the tow contribution tracking that 80%? And then separately, is the gap between the drilled and [ TIL'd ] a function of more lumpy completions with simul or trimulfrac? Or is that a normalized spread?

So I'd say let's start with maybe the second part first. It's always going to be a little bit of a lag we've got in how we drill these wells and then getting the completion crews in, making sure all the midstream is in place and the facilities are built and then bringing them online. And so you'll see a little bit of lumpiness as we do depending upon the size of the pads and how the overall development works, but always expect to see a little bit of a lag there. With respect to how many have 6 months of production or more, I don't know that number off the top of my head. Clearly, we're happy about what we've seen so far. With respect to sort of when we really understand what that fourth mile contribution looks like, I think we're still a little early from that. As we model these things out through simulation, the production profiles look reasonably similar during the early period of the well and then they diverge a little bit as you get forward in time. And so we really need to see as they go through this initial flow period and they start to get into more stabilized flow in the future, you can start to tell the difference on -- really see the difference on how that 4th mile is contributing. So we're still a little too early there to make a call. We like what we're seeing. Everything we're seeing is in line with expectations, and so we're excited about the program. But I think we're still just a little bit too early to call to validate like we did with 3 miles previously that we're getting full contribution from that last mile. So I'm encouraged with what we saw in the 3-mile program. We're actively monitoring these wells as we move forward. And as we have confidence on whether or not we're seeing incremental contribution from that 4th mile, we'll certainly bake it into our plans and pass that along, but I still think it's just a little too early right now.

Thanks I appreciate that.

I think the one thing I'd add to that, Danny, is we pump tracers on all of our 4th mile wells, and we're seeing tracers from those toast stages back at the surface. So we know those stages are contributing. And so all indications are certainly positive at this point.

For my follow-up, as you broaden the chemical program across hundreds of wells, how are you identifying the best candidates? And are you seeing meaningful differences in response by area or well vintage?

I think the -- again, we're early in the testing phases of this chemical program and the team -- and it's very -- it's not only one type of thing that we're trying. We're trying several different things. And so the team has a selection criteria where they look to see what wells they think may be the best candidates for these types of jobs, and that's going to vary a little bit by the specific circumstances of that well. And so yes, there's a whole -- we're trying several different types of chemical treatments. We do have a selection process for trying to determine which wells are the best candidates, and we're marching through those. We'll execute them, monitor performance, learn from it and then move forward. But we are -- again, we're encouraged with early results, but we need a little more -- enough so that we want to expand this program. And as we have more information and more data, we'll certainly be passing that along and incorporating into our future expectations.

Your next question comes from Paul Diamond from Citi.

I want to talk a bit about Slide 6, you guys list a pretty robust opportunity set with a whole block of initiatives. Can you put some, I guess, clarification around that, like which ones are the kind of low-hanging fruit versus which ones we would expect to see more over time? Is there any that kind of stand out one way or the other?

So I'd say that, again, as we look at these chemical jobs and really more broadly, our overall base production initiatives, there is a whole wide array of opportunities. Certainly, one of the largest costs and impacts to production we see is if we can improve the run time and efficiency of our ESPs. And so we've got a whole team and in fact, we've organized around the entire organization around really making sure we've got a team dedicated to improving our ESP run time and our ESP performance. And I think we're seeing some strong returns on that program. So we haven't highlighted that here, but I just do want to give the team a shout out for their efforts on that. And that certainly is something that we see a lot of opportunity from a potential cost structure and run time standpoint. From a chemical perspective, I would say it's -- again, we've got some -- we are encouraged with what we're seeing through several of these different types of jobs. We've seen some pretty significant improvement in well productivity on a few of them we've done. We need to make sure that we understand the mechanism of why that worked and to make sure that it's replicable and that we can do good candidate selection here. So again, as we -- we're excited about several of these things. And as we get some more -- again, as we get confidence in the repeatability of the results, and we'll know that as we are able to expand this program and see the production response of then we'll be passing that on. Darrin, anything to add?

Yes. No, I think you covered it well, Dan. I don't have any additional.

Got it. And just for a quick follow-up. I know you guys are dropping the second frac crew on 2H. Do you have any update on the timing of that? Should we expect that like mid-Q3, late Q3? Just how to think about capital timing in 2H?

Yes. So we dropped that in July. And so we've already dropped that frac crew, which is why we're confident about seeing 3Q capital come down.

[Operator Instructions] Your next question comes from Geoff Jay from Daniel Energy Partners.

I just was hoping to get a little more color maybe on some of the production optimization efforts. Is there an element of that, that's more widely deployed that's a bigger contributor than the others? I would assume the chemicals is probably a low contributor, maybe the run time is a bigger one. I guess what I guess I'm getting at is I think a lot about the AI deployment. I mean, how broadly is that deployed? Is there a lot more room there? Or are you doing a lot with the AI optimization of artificial lift?

That's a great question, Geoff. And I'd say that we've really implemented that pretty widely across the field at this point for our wells that are on rod pump. And really, at the end of the day, almost every well that we've got within the field will end up on rod pump. We've got a few that may be on longer-term gas lift. But essentially, we've got nearly every well ends up on rod pump, and we've been able to use the ability of the computer through artificial intelligence to really optimize that entire rod pump program to ensure that not only are we sort of loading that pump properly, but what that results in is to ensure that the wear on the pump is reduced and that the production is improved. And so we've done that pretty broadly across the field. I suspect that there's room for optimization on that. But with respect to implementation, it's pretty broadly implemented. The nice thing about that is we've seen the success there. And so now I think you may see us looking at what other opportunities do we have to ensure that the computer can optimize aspects of our operation that instead of being optimized on a daily or a weekly or sort of maybe even less infrequent basis where they could be optimized almost instantaneously to make sure that we're maximizing production. So I think that was a good win for us and is very broadly adopted across the field as you -- sort of as you pointed out. Now from a chemical standpoint, again, it's going to depend on the specific issues we see with that well and the opportunity of the chemical that we're injecting. But -- so those may be a little bit more specific and bespoke depending upon what's going on with the well, but there are some initiatives like this rod pump that we've done across the entire sort of rod pump fleet. Additionally, I mentioned earlier, we've got a lot of -- we've got a whole fleet of workover rigs that help us continue to make sure that our base production is running effectively and efficiently. And we're now using the computer to help us schedule all of those jobs. And so as you can imagine, in the past, you would have a human look through and determine as a well goes down, and we have wells going down every day, we've got over 5,000 wells in the basin. We would have to optimize where does that workover rig go next. And so you're making all of those judgment calls about proximity to the next well, the amount of production that was off, the cost of the job, the availability of parts to do the job because you never wanted those things to have any idle time. Well, the computer can do all of that scheduling math very, very effectively and very quickly. And so we're looking for that sort of scheduling optimization as well, which is not something we may classically talk about as part of our base production enhancement initiatives, but it's a big -- it has potentially a big effect to make sure that we're very optimized on scheduling all those workover rigs out within the field. So long story short, we've got -- I think we've got a lot of different initiatives. Some of them will have more broad impact, as you mentioned, some may be a little more focused. but we think all of them have the opportunity to increase value from our base production, and we're excited about all of them.

And there are no further questions at this time. I will turn the call back over to Danny Brown, CEO, for closing remarks.

Thanks, Julie. Well, before we wrap up, I'd like to thank all of our employees for another outstanding quarter. Their commitment to safety, operational excellence and continuous improvement is what allows Chord to consistently deliver strong results while strengthening the business for the long term. As we step back and look at where Chord stands today, I think we're in an excellent position. We have a high-quality oil-weighted asset base with a long runway of attractive inventory, robust, sustainable free cash flow and one of the strongest balance sheets in the sector. Those advantages give us confidence that we can continue creating value across a wide range of commodity price environments. I'd also be remiss if I didn't take this opportunity to provide a thank you to a member of our team who will be moving on. Shannon Kinney, our General Counsel, will be returning to ConocoPhillips, where she spent many years to fill their open General Counsel position. We're sad to see her go, are thankful for her contributions and wish her all the best. And with that, I'd like to thank everyone for your continued interest in Chord Energy. We appreciate you joining us this morning, and we look forward to speaking with many of you over the coming weeks.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect. Thank you.