Logo of jester cap with thought bubble.

Image source: The Motley Fool.

DATE

Wednesday, May 6, 2026 at 11 a.m. ET

CALL PARTICIPANTS

  • Chief Executive Officer — Danny Brown
  • Chief Strategy Officer and Chief Commercial Officer — Michael H. Lou
  • Chief Operating Officer — Darrin J. Henke
  • Chief Financial Officer — Richard N. Robuck
  • Vice President, Investor Relations and Treasurer — Bob Bakanauskas

Need a quote from a Motley Fool analyst? Email [email protected]

TAKEAWAYS

  • Adjusted Free Cash Flow -- $324 million, which management stated "substantially exceeding expectations," with $145 million returned to shareholders via base dividend and share repurchases.
  • Oil Volumes -- Delivered above the high end of guidance; 2026 oil volume outlook increased by 2,000 barrels per day, with all additional production supported by unchanged capital guidance and a "slight increase" in LOE.
  • Cash to Balance Sheet -- $175 million added after lease acquisitions, as explicitly described in the prepared remarks.
  • Full-Year Free Cash Flow Guide -- Approximately $1.4 billion expected in 2026 assuming $80 oil and $3.25 per MMBtu gas; management called for "robust" distributions to shareholders to continue this year.
  • Shareholder Returns Framework -- Continued focus on "healthy and sustainable base dividend, supplemented by share repurchases," with no near-term plans to resume variable dividends; excess free cash flow to "go to the balance sheet."
  • Hedge Position -- "one third" of 2026 projected oil volumes hedged and "less than 15%" for 2027, as noted by management.
  • Operational Efficiency -- Drilling and completion cost per foot down 37% over the past four years; future company-level F&D costs trending 22%-25% lower compared to prior years, explicitly referenced by management.
  • Four-Mile Lateral Program -- Successful execution and TIL of first full four-mile BSU development at the Tuni pad, with five wells and initial performance and execution "in line with expectations."
  • Development Program Mix -- About 40% of TILs and 60% of spuds expected to be four-mile laterals in 2026; roughly half of inventory characterized as four-mile locations, set to continue ramping into next year.
  • Base Production Optimization -- Efforts such as accelerating workovers, AI-optimized artificial lift, and chemical jobs have provided "a dramatic increase in productivity on our older wells" according to COO Darrin J. Henke, with additional workover rigs brought online targeting longer-term shut-ins.
  • Crude Realizations -- Chord is "realizing modest premiums to WTI" with improved oil price differentials expected to persist into the second half of the year.
  • Marcellus Asset Status -- Reiterated as "non-core"; company is "absolutely open to divesting it, but we want to do so in a manner that maximizes value for shareholders."
  • Capital Spending Discipline -- Drilling and completions capital to "stay consistent with our February outlook;" management emphasized not focusing on capital reductions given the improved macro environment, but rather allowing incremental volumes to roll through if supported by efficiencies.
  • M&A Approach -- Management stated readiness for Bakken opportunities, but emphasized discipline: "We are believers in consolidation and think we can compete well in any process, but we will also be very disciplined in what we do."
  • Organizational Structure -- Recent creation of production engineering teams dedicated separately to ESP wells and non-ESP wells, which has enhanced focus and "big impact" on performance for the lower-producing well group.

SUMMARY

Chord Energy Corporation (CHRD 5.58%) increased its 2026 oil production guidance by 2,000 barrels per day while keeping total capital spending flat, enabling more than $40 million incremental free cash flow at $80 oil prices. Management confirmed $324 million adjusted free cash flow during the quarter, with $145 million returned to shareholders and $175 million added to the balance sheet following lease acquisitions. Roughly one third of 2026 and less than 15% of 2027 oil volumes are now hedged, reflecting elevated supply risk management. Major operational improvements include a 37% reduction in drilling and completion cost per foot over four years and company-level F&D costs 22%-25% below historical levels. The inaugural Tuni pad four-mile lateral project was executed and the company will have approximately 40% of TILs and 60% of spuds from four-mile laterals this year, reflecting a scalable shift in drilling strategy.

  • Initiatives using advanced artificial lift and increased workover activity resulted in significant incremental output from mature wells above baseline declines.
  • Management reiterated excess cash flow will be directed to deleveraging, with no immediate plans to reinstate a variable dividend, emphasizing a preference to allow "incremental volumes roll through" if efficiency continues improving.
  • Chord’s approach to oil price risk combines systematic hedging—locking in up to 55% of volumes in prompt quarters above price thresholds—with selectivity on longer-dated positions as market conditions evolve.
  • Capital spending flexibility exists within the program but will not be reduced further absent material market change, and volume guidance may see upside if operational outperformance continues.
  • Management confirmed Marcellus acreage remains targeted for eventual divestiture, yet will be held until a value-maximizing opportunity arises, consistent with previous company messaging.

INDUSTRY GLOSSARY

  • TIL (Turn In Line): Industry shorthand for wells brought into initial production after completion.
  • BSU (Bakken Spacing Unit): Designated acreage block for comprehensive well spacing and lateral development in the Bakken formation.
  • ESP (Electric Submersible Pump): An artificial lift method for high-rate oil production using submersible pumps placed downhole.
  • Workover: Operations or maintenance work performed on existing wells to restore, sustain, or enhance production.
  • F&D (Finding and Development) Cost: Per-unit metric reflecting all capital required to add new proved reserves, including drilling, completions, and facility expenses.
  • LOE (Lease Operating Expense): Ongoing expenditures for routine operations and maintenance of producing oil and gas properties.
  • Spud: The moment when drilling operations commence on a new well location.

Full Conference Call Transcript

Bob Bakanauskas: Thanks, and good morning, everyone. This is Bob Bakanauskas, and today, we are reporting our first quarter 2026 financial and operational results. We are delighted to have you on the call. I am joined today by Danny Brown, our CEO; Michael H. Lou, our chief strategy officer and chief commercial officer; Darrin J. Henke, our COO; Richard N. 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 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. I will now turn the call over to our CEO, Danny Brown.

Danny Brown: Thanks, Bob. Good morning, everyone, and thanks for joining our call. Last night, we issued our first quarter results and our updated investor presentation. These materials outline key strategic, operational, and financial details along with our updated 2026 outlook. I plan on highlighting a few key points, then we will open it up for Q&A. To start, looking at the first quarter briefly, Chord Energy Corporation delivered another consecutive quarter of solid operating performance. The team did an excellent job executing through adverse weather conditions and some midstream constraints to deliver oil volumes above the high end of guidance. Additionally, we maintained solid cost control.

Adjusted free cash flow for the first quarter was $324 million, substantially exceeding expectations, and we returned $145 million of this amount to shareholders through a combination of our base dividend and share repurchases. After accounting for lease acquisitions occurring in the quarter, we were also able to send $175 million to the balance sheet. Second, as we assess the macro environment, there is clearly an unprecedented amount of volatility and uncertainty in commodity markets. Chord Energy Corporation has been running a maintenance-plus program for more than five years, with the goal of maximizing free cash generation for our stakeholders.

One of the key factors influencing this strategy has been the high levels of excess low-cost oil capacity, which has weighed on global oil markets and contributed to persistent backwardation. We will continue to monitor global supply-demand balances and, for now, given the uncertainty of how much and how quickly oil volumes will find their way into the market, we are comfortable staying the course with a flat-to-slight-growth volume outlook. Given this, drilling and completions capital is expected to stay consistent with our February outlook. However, we are seeing improvements in cycle times which accelerate some activity into the second quarter. Although 2026 capital spending expectations remain unchanged, we do have some flexibility within our program.

Over the past two years, we have consistently outperformed initial expectations and have generally prioritized capital reduction over incremental volume growth. In the current environment, if efficiencies continue to improve and oil prices remain high, we are inclined to allow modest volume upside rather than focusing solely on reducing capital. For clarity, this does not bias our CapEx higher but simply means we are not focused on reducing CapEx in this environment and will let incremental volumes roll through should we continue to outperform. Additionally, Chord Energy Corporation is pursuing various initiatives to optimize our production base with efforts centered around maximizing very short-cycle volumes through high-return projects across our roughly 5,000 operated wells.

These activities include accelerating workovers, reducing cycle times for down wells, various chemical jobs, debottlenecking surface constraints, optimizing artificial lift through the utilization of artificial intelligence, and a host of other projects. Accordingly, last night, we updated our 2026 outlook to reflect a 2,000 barrel per day increase in oil volumes, with a slight increase in LOE and capital remaining unchanged. Assuming $80 oil, the net impact is over $40 million in incremental free cash flow versus our February expectations.

From an activity standpoint, we are currently running five rigs, one full-time frac crew, and one spot crew, with the spot crew scheduled to drop around midyear which, because of faster cycle times, is a little earlier than our February expectations. We continue to expect approximately 80% of TILs will be longer laterals split fairly evenly between three- and four-milers. We have also updated our 2026 guidance to reflect improving oil realizations. Currently, Chord Energy Corporation is realizing modest premiums to WTI and we expect that to persist through most of 2026 given the structure of the futures curve and linkage to waterborne crudes.

Assuming benchmark prices of $80 per barrel of oil and $3.25 per MMBtu of natural gas for the balance of 2026, we expect to generate approximately $1.4 billion of free cash flow this year. With high levels of free cash flow anticipated, we expect shareholder distributions to remain robust in 2026 with a continued focus on a healthy and sustainable base dividend, supplemented by share repurchases. In the current environment, share repurchases continue to look attractive. However, in the interest of avoiding procyclical buybacks, Chord Energy Corporation may choose to taper repurchases if and when we see higher oil prices more fully reflected in our share price.

In addition, we currently do not envision resuming variable dividends and plan to let excess free cash flow go to the balance sheet. This will reduce net debt and allow us to create per-share value in the future. Turning to our updated hedge position, you can see Chord Energy Corporation added significant hedged volumes in 2026 and a moderate amount in outer years as well. As a reminder, our hedge program is designed to systematically hedge more when prices are above historical levels and conversely hedge less when the strip is below historical pricing.

In any prompt quarter, we have the ability to lock in up to 55% of our volumes if pricing surpasses certain thresholds, and the program deliberately moves at a slower pace further out on the curve. Currently, we have approximately one third of our 2026 oil volumes hedged and less than 15% of 2027. Turning to the long lateral front, I am happy to report Chord Energy Corporation successfully executed and turned in line its first full four-mile BSU development, the Tuni pad. The pad consisted of five wells, including one alternate shape, and Chord Energy Corporation was able to clean out to total depth on all wells. Both execution and early performance are in line with expectations.

Slide 11 in our investor presentation highlights the Tuni success as well as Chord Energy Corporation’s progress on four-mile laterals in development across the perimeter of the basin. A significant reduction in drilling and completion cost per foot underpins the strong economics of these wells. Slide 10 on the upper right illustrates a 37% reduction in Chord Energy Corporation’s D&C cost per foot over the past four years. These benefits can be seen in Chord Energy Corporation’s improving program-level capital year over year. If you look at volumes delivered relative to capital spent—essentially the inverse of an F&D calculation—you can see the 2026 program is more efficient than 2025.

Additionally, Chord Energy Corporation’s future F&D costs on a company level have trended 22%–25% lower over the past few years, clearly demonstrating sustained efficiency gains. Overall, we are very pleased with execution and early results from the four-mile program. As a reminder, Chord Energy Corporation is scaling its four-mile program in 2026 with approximately 40% of TILs and 60% of spuds expected to be four-mile laterals. In closing, Chord Energy Corporation remains committed to delivering affordable and reliable energy in a sustainable and responsible manner. We continue to improve the business, growing production while simultaneously improving the depth and quality of our inventory, driving operational efficiencies, and enhancing free cash flow. We will now open the call for questions.

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any key. One moment for your first question. Your first question comes from John Abbott with Wolfe Research. Please go ahead.

John Holliday Abbott: Hey, thank you very much for taking our questions. Danny, I appreciate the opening comments on the macro front; there is a lot of uncertainty there. My two questions are really on growth and on inventory. My understanding from our previous virtual events is that you do have the ability to grow at some point when the fundamentals support the long-term commodity price being higher. How do you think about that appropriate long-term price? And then the second part is on inventory: if you do grow when the commodity price is higher, how does that change the depth of your inventory as commodity prices were to go higher?

Danny Brown: Thanks, John. Those are both great questions. From an oil price perspective, you are exactly right in our philosophy. It is not necessarily a specific price, but whether the durability in the macro setup supports that price over the long term. That has been fundamentally why we have been focused on more of a maintenance program as opposed to a growth program, because we have seen significant behind-choke volumes in the global market that could come to market at any time.

That could undermine our price expectations, and we could invest a lot of capital and not get the returns off that investment that we may have expected when we undertook it in the first place, and we do not want to be exposed to that. As I look at the amount of volume not flowing currently within the global market, we just do not know how much and how quickly this volume will return to the market, which means the durability of any price signal is something we are somewhat circumspect on.

If we did see a more constructive macro setup from a supply-demand balance where we thought the durability of, let us say, above mid-cycle pricing would be sustained for some period of time, we are in a great position in that we have a deep bench of low-cost inventory that we could accelerate into. We could deliver modest growth into the system—probably mid-single digits is something that we would be comfortable with if the structural setup was conducive to that. From an inventory standpoint, if we saw that setup and we were at, call it, above mid-cycle pricing and we thought that would stay for some period of time, clearly that is a tailwind for our inventory.

We would look at new development opportunities; some incremental evaluation on our spacing would likely be appropriate at that point; and some areas on the periphery of the basin would come into the fold. So I think it would be a tailwind to inventory. We have been able to maintain 10 years of inventory for the last five years. I would expect in a higher commodity price environment, if we did push growth into the system, that would also mean our inventory was marching up as well.

John Holliday Abbott: Appreciate it. Thank you, Danny.

Operator: Your next question comes from Oliver Huang with TPH. Please go ahead.

Oliver Huang: Good morning, Danny and team, and thanks for taking my questions. I wanted to start on the base production enhancement program. There were a number of callouts in the release—AI-optimized artificial lift, workover-intense programs, less downtime, among other things. Are you viewing this as something more structural, driving lower base declines for the portfolio across multiple years, or is this more of a one-time addition on the set of wells the program is targeting? I am trying to understand the sustainability of that uplift better and what sort of upside running room there might be beyond what is baked into this year’s guide.

Danny Brown: I think it is a great question, Oliver, and the answer is a bit of both. We have had efforts underway as an organization to optimize the production from our base wells and have seen early success. In a world where the market is telling us it needs very short-cycle oil, we have had opportunities to lean in. I am going to ask Darrin to talk through some specifics and some of the early results we are seeing.

Darrin J. Henke: Yeah, Oliver, we have seen a dramatic increase in productivity on our older wells. We have lowered some rod pumps further into the wells, and we have adjusted our artificial intelligence to focus on maximizing productivity out of our older rod pump wells. As you see on slide 12, lower right, you can see a positive impact to base production and really arresting decline on this group of wells. The teams are consistently generating new ideas, and as Danny said, it will take time to figure out how sustainable these changes are to the wells that have already improved.

We have picked up a couple of additional workover rigs, we are focusing on longer-term shut-in wells that have some challenging downhole problems, and we are finding that we are able to get those wells back online and producing as well. There are a number of wells in that category that we are working on. While we see these higher prices, we are definitely trying to take advantage of maximizing our base production.

Oliver Huang: Thanks for that color. For my second question, on the four-mile laterals, you have talked about verifying the toe contribution with tracers. As you get more data and a greater sample set, is there a point or quantitative benchmark where you would revisit and start to assume greater than the 80% contribution on the last mile of the well’s lateral if the data were to be supportive?

Danny Brown: I think the answer is yes. Just like the three-mile laterals—after we got enough production history, we said we were no longer underwriting that last mile at 80%; we moved that up to 100% because we were seeing it in the production data. I think it would be a similar case for four-mile laterals. It is a little too early for us to say that right now, but we are continuing to monitor production. If we continue to see positive indications, we will come out with an update at some point in the future indicating that we are getting more from that last mile than we are currently underwriting.

Oliver Huang: Makes sense. Thanks for the time.

Danny Brown: Thanks, Oliver.

Operator: Your next question comes from BMO Capital Markets. Please go ahead.

Analyst: Hi. This is Jack Kindergen 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?

Danny Brown: Yeah, Jack, good question. Over the end of the first quarter and into the second quarter, you are seeing stronger differentials in the basin. As you think about Brent-TI differentials, they have widened. A lot of our barrels get to the coastal markets, and you are seeing very strong differentials in basin. A lot of that is going to depend on 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.

Analyst: Understood. Thank you. And you touched on your capital plans for the balance of the year a little bit, but seeing the oil uplift in 1Q and the better 2Q and 3Q guide, I am trying to get a sense of the April dip and whether there is a case for running higher activity—filling in completion white space—just to maintain operational momentum even if it leads to some CapEx creep.

Danny Brown: I think at this point, we are pretty happy with our activity levels. We have the spot crew we will release later this year, and we run that crew continuously until we drop it. It is not like we need to manage white space in between an existing program; we will just drop that. I do not think there is a lot of efficiency improvement we would pick up by pushing incremental activity through the system. We are happy with our activity levels where they are right now. We will continue to monitor the macro situation, but it is too early for us to pivot off that. We are comfortable with where we are now.

Analyst: Great. Thank you for the time.

Operator: Your next question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Michael Hanold: Thanks. I was wondering if you could pivot to shareholder returns. You all had a pretty good appetite to be 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 procyclical, but when you look at your stock price today with oil near $100 a barrel, is this an opportunity for you to continue to be assertive with buybacks and push it a little bit harder? Or would you rather wait for a more countercyclical time to get that robust with buybacks?

Danny Brown: Scott, I would frame it this way. If you look at the headline oil price, our stock is not underwriting anywhere near that level, in our opinion. We really like where our stock is at right now, and buybacks are very attractive at current levels. At some point, it may be that we see our stock price underwriting at significantly higher oil prices; we are not seeing that today, but we may at some point. At that point, we would consider tapering back on buybacks to avoid being procyclical. But I like where our shares are now.

Scott Michael Hanold: Okay, understood. And looking at the Tuni pad, could you talk about the learnings from that? Have you seen cost reductions consistent or better than expected, and what does that mean for four-mile pad development moving forward?

Danny Brown: Generally speaking, we are really happy with what we saw at Tuni. Anytime you get to pad-level development, you pick up efficiencies versus doing one-offs. Getting to pads is a pretty big cost improvement for us organizationally. I will let Darrin expand.

Darrin J. Henke: We have 12 four-mile laterals now producing, five of them on the Tuni pad, and we have drilled 33 four-mile laterals. There are tons of learnings not only on Tuni but across other four-mile pads. We are consistently getting those wells drilled with one BHA. We recently drilled our first hairpin with one BHA, a pretty neat accomplishment. Tuni allowed us to put it all together on one pad and we saw efficiencies across the entire pad that we will take into future pads. As far as costs and performance, the costs were in line with what we expected on that pad, and well productivity is in line with expectations.

We are very pleased with what we are seeing in our four-mile program at this time.

Scott Michael Hanold: Appreciate that. Thank you.

Operator: We now have a question from Neil Dingmann with William Blair. Please go ahead.

Neal Dingmann: My first question, Danny, is on capital allocation. Specifically, I have seen a couple of guys now talk about dialing down buybacks perhaps in the turn-up cycle. What are your thoughts on incremental buybacks versus debt repayment for the remainder of this year if prices stay here?

Danny Brown: In the current environment, we think our return of capital framework provides a great approach for capital allocation. Based on a lot of investor feedback, we are not focused on variable dividends at this point. So our return of capital program is really going to be made up of what we think is a strong base dividend plus share repurchases. We really like the shares where we are at right now. We recognize that if oil prices are elevated, we may think about whether it is the right time to be buying back shares aggressively. We have said for a long time we are not fans of procyclical buybacks.

I do not think with where we are currently that is what we are doing. We think shares are very attractive, and they are currently commanding a significant focus from a capital allocation perspective.

Neal Dingmann: Makes sense. Thank you. Second question, around slide 15 and inventory. You suggest—and I agree—10-plus years of low breakeven inventory. Have the assumptions changed at all when you include your price deck and costs? What dictates how you view the breakevens and the corresponding inventory?

Danny Brown: The inventory that we put out there is really low sub-$60 WTI inventory, and that determines the count. If our pricing assumptions from a commodity perspective were higher than that, you would see more inventory from a count perspective. If structurally we get to a situation where we see a longer-term higher oil price, then we might think differently about our inventory position and you would see more inventory flow in. But we are looking at it from a sub-$60 standpoint.

Neal Dingmann: Great. Thank you, Danny.

Danny Brown: Thanks, Neil.

Operator: Your next question comes from Pickering Energy Partners. Please go ahead.

Analyst: 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. 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.

Analyst: Got it. That makes sense. As a follow-up, there is some volatility this morning. It seems clear that activity levels are unlikely to change given the current market dynamics. What other levers can the company pull to capitalize on higher prices?

Danny Brown: When we say activity, our drilling and completion activity, we do not anticipate changing. We have flexed up on some of the very near-term, more OpEx-related opportunities—workovers and chemical jobs—across our 5,000 existing wells. Those can deliver very short-cycle volumes at incredibly high IRRs and profitability. You have seen us deliver some incremental volumes in the first quarter as a result. The other thing I would say is we continue to focus on improvement across all aspects of our business. We cannot control oil prices, but we can control our cost structure and how we develop the field.

We have around 800 people who wake up every morning focused on making tomorrow better than today from a cost and productivity perspective. We will flex into those short-cycle OpEx opportunities that can deliver oil next week or next month, and we will keep improving the business across the board.

Analyst: That is great color. Thanks for your time.

Danny Brown: Thank you.

Operator: You have a question from Texas Capital. Please go ahead.

Analyst: Hey, good morning all, and thanks for taking my questions. For my first one, building off what you just mentioned, could you provide some color on the organizational changes you have made—whether it is standing up new teams or shifting allocation of resources—that have been driving the improvement in base production optimization initiatives?

Danny Brown: It is a great question. One of the most significant organizational changes we have made recently is within our production engineering team. We have bifurcated that team into those looking at our wells on ESPs—our high-rate wells—and a separate team looking at the balance of our wells, measured in the thousands, that are not on ESPs. Naturally, a team responsible for all wells will appropriately focus on the high-rate ESP wells because they have the biggest impact, but that can mean you do not focus as much on the other wells, which in aggregate can still provide meaningful value. Recognizing that dynamic, we now have a group dedicated to the lower-producing wells.

In aggregate, they can have a big impact on what we deliver and what our overall cost structure looks like. We have seen success with that, and I am pleased with the focus and results from both teams.

Analyst: Terrific. For my follow-up, you are guiding around 40% of 2026 TILs 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 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: We think about 50% of our inventory as four miles. In any given year, our development program will largely mirror our inventory makeup—some years slightly above, some slightly below that 50%. Because we are spudding about 60% four miles this year, that will obviously roll into 2027 from a production perspective. We have started that ramp this year and will continue it into 2027.

Operator: Your next question comes from Capital One. Please go ahead.

Analyst: Hey, thanks for the time. I wanted to ask you about the XPO assets. I recall you are in the process of re-permitting most of those wells for longer laterals. Where are we in that process and when might we see some of those wells coming into the fray?

Danny Brown: As we moved into four-mile laterals and looked at spacing and lateral lengths, we wanted to make sure we maximize the contribution from that asset. We have taken our time doing that. As we look toward developing in that area, that is probably more of a late 2027 phenomenon. We might get some contribution in 2027, but more likely going into 2028.

Analyst: Okay, sounds good. I am sure you cannot comment too much on this one, but what is the latest messaging regarding long-term plans for the Marcellus acreage?

Danny Brown: The messaging around Marcellus remains consistent. We continue to see it as a non-core asset and have been very clear that we are looking to maximize value for our shareholders, which would include divesting that asset. We are not in a rush, but it is non-core, and we want to maximize value from it. In the meantime, it has very low friction cost to hold, and you can see from our first quarter results the significant value that asset contributed. We are absolutely open to divesting it, but we want to do so in a manner that maximizes value for shareholders.

Analyst: Sounds good. Thank you, Danny.

Operator: As a reminder, if you wish to ask a question, please press 1. Your next question comes from Jefferies. Please go ahead.

Analyst: Hey, Dan and team, appreciate you getting me on. Just a quick one for me. I heard from NOG earlier last week about a large Bakken package coming for sale. What are your thoughts on M&A in the current elevated price environment, and what type of leverage are you able to stretch to in an upside scenario for the right type of inventory mix?

Danny Brown: I will make some opening comments, then pass it over to Michael. From a positioning perspective, our footprint in the Bakken stretches across the entirety of the basin, so we think we could be quite competitive on any package that comes to market. We can bring synergies to bear like no one else can. We have great supply chains in place and know the subsurface well. We are believers in consolidation and think we can compete well in any process, but we will also be very disciplined in what we do.

You have not seen us win every deal in the Bakken, and oftentimes that is because the market-clearing price was not something that would make us a better company at the end of the day. Michael?

Michael H. Lou: John, usually when prices are moving very rapidly, there is a bit of a lull in M&A opportunities. As you have seen elevated pricing for, call it, two months now, I think you will see some assets come to market. The big question is whether you can close the gap between buyers and sellers in terms of valuations. As Danny mentioned, we think we are in great shape to be a consolidator in the Bakken, but we are going to be disciplined in the way we look at that marketplace.

Operator: This looks like all the questions for now. I will turn the call over to Danny Brown for closing remarks. Please continue.

Danny Brown: Thanks. To close out, I want to extend my sincere thank you to all of our employees, who through their hard work have positioned us for continued success. Chord Energy Corporation has consistently delivered results that have exceeded expectations while improving the quality and depth of our inventory and enhancing profit margins. Chord Energy Corporation has created what we believe is a valuable and increasingly rare asset: 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. Thank you for joining our call.

Operator: Ladies and gentlemen, this concludes today’s conference call. Thank you for your participation. You may now disconnect.