Coterra Energy Inc. (NYSE:CTRA) Q1 2025 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q1 2025 Earnings Call Transcript May 6, 2025

Operator: Thank you for standing by. My name is Kayla, and I will be your conference operator today. At this time, I’d like to welcome everyone to the Coterra Energy First Quarter 2025 Earnings Call. [Operator Instructions] I would now like to turn the call over to Dan Guffey, VP of Finance, Investor Relations and Treasurer. You may begin.

Dan Guffey: Thank you, Kayla. Good morning, and thank you for joining Coterra Energy’s First Quarter 2025 Earnings Conference Call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO and President; Shane Young, Executive Vice President and CFO; and Blake Sirgo, Senior Vice President of Operations; Michael Deshazer, Senior Vice President of Business units is also in the room. Following our prepared remarks, we will take your questions during our Q&A session. As a reminder, on today’s call, we will make forward-looking statements based on our current expectations. Additionally, some of our comments will reference non-GAAP financial measures. Forward-looking statements and other disclaimers as well as reconciliations to the most directly comparable GAAP financial measures are provided in our earnings release and updated investor presentation, both of which can be found on our website. With that, I’ll turn the call over to Tom.

Tom Jorden: Thank you, Dan, and thank you for all of you who are joining us on this call. Coterra had an excellent first quarter. We delivered oil production near the high end of our guidance and natural gas production that exceeded the high end of our guidance. CapEx came in near the low end of our guidance. Furthermore, we generated excellent financial results, returned a substantial portion of our free cash to our owners and retired $250 million of our term loans. We closed on the Franklin Mountain and Avant acquisitions and immediately launched into the job of integrating these high-quality assets into our operations. We are pleased to report that we have identified and captured significant operational efficiencies and are bringing these new assets into emissions performance consistent with Cote standards and have seen well performance on recent flowbacks that exceeds our expectations.

Shane and Blake will provide more detail on our financial and operational results and outlook. We hope that you will note that the opening slide in our updated investor deck discusses who is Coterra and why own Coterra. We think that the recent volatility in the commodity markets, uncertainty over the impact of tariffs and fears of recession strengthened the core thesis of Why Coterra. Simply put, we were built for this. Coterra is an arc, not a party boat. Our diversified revenue, low-cost oil and natural gas supply technology-driven organization, economic focus and financial discipline make us tailor made to ride out this storm and thrive in it. Slide 4 in our deck illustrates the resiliency of our cash flow under various oil and natural gas price scenarios.

None of us can predict the future. Nonetheless, Coterra is a company that can generate significant free cash flow through the cycles, generate outstanding returns and modest growth with a low reinvestment rate and maintain a pristine balance sheet. This is a testament to our organization, our assets and our culture. Why Coterra, the question answers itself in times like these. Commodity downdrafts are a part of our business. They do not come pre-labeled with how long they will last nor how severe they will be. Our experience tells us that in times like these, it is better to err on the side of caution. We have more concern regarding the oil outlook rather than the outlook for natural gas. Consequently, we are modestly pulling back some activity in the Permian Basin and incrementally adding activity in the Marcellus Shale.

In aggregate, these moves will reduce our projected 2025 CapEx by $100 million. We have plans on the shelf to make further moves up or down if we see material changes in our outlook. Our team continues to put tremendous effort into planned iterations, and we are ready for a wide range of potential scenarios. In particular, the net $100 million reduction in 2025 CapEx is a combination of $150 million of reductions in the Permian, coupled with $50 million of increases in the Marcellus. We have contingency plans that would allow us to make additional cuts from the Permian if oil prices continue to weaken. We could redeploy to highly profitable gas opportunities, advanced debt retirement, pursue opportunistic buybacks or bank the savings. Shane will comment further on this.

We have described our approach to capital allocation and planning as the difference between a rifle shot and the guided missile. Once the trigger is pulled, the rifle shot is unchangeable. The guided missile can be adjusted and repositioned along the way. In the case of our current macro environment, we not only have a guided missile, but we have a moving and unpredictable target. This screams for flexibility with low cost of supply, oil and natural gas assets robust drilling returns, few long-term vendor commitments and a culture that is adaptive, we will guide our way through 2025 and beyond. We are committed to debt reduction in 2025, particularly pertaining to the $1 billion term loan that we executed in conjunction with our recent acquisition.

As we have said, we never lose a moment sleep worrying about our debt being too low. We have seen our peers go through existential crises during significant downdrafts, and we are committed to make sure that Coterra can sell through any storm and emerge stronger because of it. Finally, I want to make a few remarks about our recently completed Windham Row project. To recap, the Windham Row infill project contains 73 total wells, 51 Wolfcamp wells and 22 Harkey wells. Our results on the Wolfcamp wells have been outstanding. While completing the Harkey wells, however, we noticed abnormally high water production on a handful of wells. We have strong evidence to suggest that this is due to behind pipe water flow from shallower zones. We have drilled Harkey wells throughout our assets in New Mexico and Texas and have only observed this phenomenon in the eastern portion of our Culberson County acreage blocks.

It is not a reservoir nor a spacing issue. This is also not a co-development or overfill issue. The evidence points to this being a near wellbore mechanical issue. We think that it is fixable, and we have well remediation solutions underway. We are very encouraged by the results that we have seen thus far. While we work through wellbore remediation, we are pausing Harkey development in this local area. It doesn’t make any sense for us to continue to drill and complete Harkey wells in this immediate area until we are fully satisfied that we have solved the issue. We expect to correct the issue during the second quarter and restore these Harkey wells to production. We believe the go-forward production forecast for the affected wells is conservative, providing potential upside for the remainder of the year.

With this pause in local Harkey development, we are pivoting to our highly productive Wolfcamp. Ironically, this will increase our capital efficiency. Our full year production guide remains unchanged with our capital guide decreasing slightly. We have never managed our company with short-term production goals. We focus on full cycle value creation underwritten by sound science, objective data and tough and disciplined decision-making. This is the winning formula for long-term value creation. With that, I’ll turn the call over to Shane and Blake to discuss our results and outlook in greater detail.

Shane Young: Thank you, Tom, and thank you, everyone, for joining us today on this morning’s call. Today, I’d like to cover 3 topics. First, I’ll summarize the highlights of our first quarter financial results. Then I’ll provide an update on our guidance, including the second quarter as well as the full year 2025. Finally, I’ll provide an update on our balance sheet and cash flow priorities for the remainder of the year. Turning to our strong performance during the first quarter. The first quarter’s performance included just over 2 months of results from our recently acquired assets from Franklin Mountain and Avant. We are pleased with the rapid integration of these assets and their contributions have been in line to slightly better than our expectations.

During the first quarter, Coterra’s oil production came in about 2% above the midpoint of our guidance, with BOEs near and natural gas above the high end of the guidance ranges. Net turn in lines during the quarter were 37 in the Permian, below the guidance midpoint of 40, and the Marcellus was at zero as expected. Free hedge revenues came in at $2 billion, up from $1.4 billion in the fourth quarter of 2024. A 45% — and 45% of revenues came from natural gas, up significantly from prior quarter due to the strong production and a 64% increase in natural gas price realizations. Cash operating cost per unit totaled $9.97 per BOE, inclusive of about $0.21 per BOE of nonrecurring costs related to the transaction. We reported net income of $516 million or $0.68 per share and adjusted net income of $608 million or $0.80 per share.

Incurred capital expenditures in the first quarter were 4% below the midpoint of our guidance range with lower-than-expected drilling and midstream costs. Discretionary cash flow for the quarter was $1.135 billion, up significantly from $776 million in the prior quarter and free cash flow of $663 million after cash capital expenditures. Looking ahead to the second quarter and full year 2025. Second quarter results will reflect a full quarter’s contribution from the recent acquisitions. During the second quarter of 2025, we expect total production to average between 710 and 760 MBoe per day. Oil is expected to be between 147 and 157 MBoe per day and natural gas is expected to be between 2.7 and 2.85 Bcf per day. These guidance ranges reflect updates in the Culberson, Harkey program.

Including the deferment of a few projects as we begin to shift to additional Upper Wolfcamp development in Culberson Cap. The net result of these changes is a reduction in oil production by approximately 5,000 barrels per day in the second quarter relative to our February expectations. Despite these second quarter changes, we are maintaining the midpoint of our 2025 annual oil production guidance. In the second quarter, we expect incurred capital to be between $575 million and $650 million, which should be the highest quarter for the year as we will have increased sales in all 3 business units. Coterra was built to respond to market signals, and we have both the ability and willingness to adapt to changing conditions. For the full year 2025, we are optimizing our investment allocation while lowering the capital range by $100 million.

We now expect incurred capital to be between $2 billion and $2.3 billion for the year, an over 4% reduction from February guidance. Given the continued constructive outlook for natural gas, we are maintaining the second rig in the Marcellus into the second half of 2025. As previously noted, this adds $50 million to the 2025 program. Should we choose to keep the second rig working for the full year, this could result in an incremental $50 million added to the program late in 2025, while still staying within our revised guidance range. In addition, due to softness in crude pricing, we are slowing development and reducing Permian activity by $150 million. If warranted, we have the flexibility to make additional adjustments do our investments later in the year that would take total investments towards the lower end of our guidance range.

For 2025, while lowering capital, we are maintaining our oil midpoint guidance and increasing the midpoint of production guidance for MBoes and natural gas, which highlights the capital efficiency of our diverse drilling opportunities. Simultaneously, we are tightening the range for MBoes oil and natural gas. And BOEs are now expected to be between 720 and 770 MBoe per day for the year. Oil is expected to be between 155 and 165 MBoe per day for the year with significant increases in each subsequent quarter. Natural gas is expected to be between 2.725 Bcf and 2.875 Bcf per day, delivering over 1 Tcf of gas on an annualized basis and providing significant leverage to higher natural gas prices. Having only a partial full quarter contribution from the new Permian assets impacts full year 2025 production by a little over 4 MBoe per day relative to the transactions had closed on January 1, 2025.

In this environment, the benefits of our diverse and balanced commodity mix become increasingly evident. On Page 4 of the new slide deck we published last night, we illustrate the durability of our free cash flow across multiple commodity price files. Coterra is positioned to thrive and maintain a reinvestment rate of around 50% of cash flow in a variety of commodity price scenarios and ranges of oil to gas price ratios. Regarding our 3-year outlook, we maintain our conviction in our ability to deliver consistent, profitable growth to our shareholders. As we’ve stated before, our deep project inventory can deliver 5% or greater oil volume growth and 0.5% BOE growth over this period by investing between $2.1 billion and $2.4 billion of capital per year.

If we choose to do so, even with the changes to our 2025 that we announced today. These growth rates like legacy Coterra organic growth in 2025 and include our recent acquisitions for 2026 and 2027 growth. This outlook delivers increasing capital efficiency and is designed to afford Coterra the flexibility to reallocate capital between our business units as market conditions change. We believe this outlook has an attractive, repeatable level of reinvestment and generates meaningful free cash flow to underpin both our shareholder returns and our deleveraging goals. Turning to shareholder returns on the balance sheet. Yesterday, we announced a $0.22 per share dividend for the quarter. This remains one of the highest yielding base dividends in the industry at over 3.4% and we remain committed to reviewing increasing the base dividend on an annual cadence.

During the first quarter, we repaid $250 million of our outstanding term loans that were used as part of the financing of our recent acquisitions. We ended the quarter with an undrawn $2 billion credit facility and a cash balance of $186 million for total liquidity of $2.2 billion. We expect to continue to prioritize deleveraging. And in the current environment, we expect to fully repay our $1 billion term loan during 2025. As a result, and as previously noted, share repurchases will be back-end weighted in the second half of 2025. We are focused on quickly getting our leverage back to home to around 0.5x net debt-to-EBITDA. Coterra is committed to maintaining a fortress balance sheet that is strong in all phases of the commodity cycles, enables us to take advantage of market opportunities and protects our shareholder return goals.

In summary, Coterra’s team delivered a quarter of high-quality results, both operationally and financially and across all 3 business units. These results show that we’ve hit the ground running in 2025. For the remainder of the year, we expect strong quarterly oil production increases substantial free cash flow generation and rapid deleveraging. With that, I’ll hand the call over to Blake to provide additional color and details on our operations. Blake?

Blake Sirgo: Thanks, Shane. The first quarter of 2025 was marked by the integration of our new Delaware assets into our Permian operations program. Our teams have been hard at work, applying our best practices to these assets, and we are already seeing wins in the field. Our D&C team has been able to lower our dollar per foot by 10% from the previous operators by bringing our program efficiencies to bear. Initial productivity from these new assets is beating our expectations, and we are iterating on well spacing and frac design to further improve capital efficiency. Our production and midstream teams are focused on minimizing downtime and as such, have realized a substantial drop in flared volumes across the assets. We also see significant opportunities to optimize the infrastructure and midstream assets across our Northern Delaware position.

Our updated Permian plan calls for a reduction in activity as we respond to headwinds in the oil market. We now plan to run 7 rigs in the second half of 2025, down from our original guidance of 10 rigs. These changes in activity reduced CapEx in the Permian by $150 million. We maintained significant flexibility across our rig and frac fleets and have additional off ramps available to us throughout the year. In Culberson County, we have finished completing our Windham Row Harkey wells. As Tom mentioned, we have encountered some mechanical issues on Windham Row, resulting in mixed results for our Harkey wells. We have collected data that indicates a lack of adequate cement on certain wellbores, which has allowed water from our shallow disposal zone to find its way into portions of the Upper Bone Spring interval.

This has led to increased water production on roughly half of our Harkey wells on Windham Row. It made it difficult for the affected wells to draw down reservoir pressure and produce the expected oil volume. We have kicked off a workover program to remediate these wells, and our early results are encouraging. This remediation campaign will continue over the next several months, and we will be closely monitoring the production response from these wells. While we are working through these remediation efforts, we will focus our row developments on the Upper Wolfcamp. The 51 Upper Wolfcamp wells brought on in Windham Row look very strong and continue to meet or exceed expectations. Our Permian team’s ability to quickly adjust to the Upper Wolfcamp and continue our efficient operations is commendable.

Their great work has allowed us to maintain our full year 2025 oil guide and improve our capital efficiency. Importantly, we expect the efficiency gains captured on Windham Row will continue on future developments. In our next 2 row developments in Culberson, the Barba Row and Bowler Row, we will focus on Upper Wolfcamp development, which has been the bread and butter of our Culberson project over the last decade. We expect no change to spacing or productivity in our Wolfcamp program. As you can see in our investor deck, by shifting more capital to the Upper Wolfcamp, our Permian asset productivity is expected to increase in 2025 and over the next few years. Coupling this increased productivity with lower capital spend, we are seeing improving capital efficiency.

Switching to our natural gas assets. Cote is happy to be back to work in the Marcellus with 2 rigs that began drilling in April and the recent completion of our Jeffers Farm project. Gas macro conditions and Northeast storage volumes continue to support a robust 2025 and 2026 strip. And as such, we are electing to add $50 million to the Marcellus program. Should conditions warrant, we hold a second on-ramp option later this year that could add an incremental $50 million to the program? Our Marcellus team continues to improve capital efficiency with our full year 2025 Marcellus dollar per foot expected to come in at $800 per foot, a 22% reduction from 2024. This improved cost structure comes on the back of a 4-mile lateral program as well as reduced D&C service costs and water transfer costs.

This plan picks up a frac crew later in 2025 and allows us to complete several great projects just in time for winter ’25 and into ’26. In the Anadarko, we are executing on a strong 2025 program with a competitive cost structure and new 3-mile projects. Strong well performance and lower costs, paired with a premium local gas market are continuing to make this asset an attractive place for Coterra to invest. We are excited to report that we have begun flowing back one of the largest natural gas developments in the Anadarko and expect to discuss results later this year. Coterra has an organization, asset portfolio and balance sheet that is positioned for success in periods of volatility. Our ability to redirect capital and optimize for the current environment is a key strength of the company.

Our teams remain as focused as ever. We are executing on our new assets in the Permian while improving their capital efficiency. We are reducing and reallocating activity in response to pressures in the crude market and taking advantage of structural natural gas macro tailwinds. We will remain nimble and focused on creating long-term value for our shareholders. And with that, I’ll turn it back to Tom.

Tom Jorden: Thank you, and we’re delighted to take your questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Doug Leggate with Wolfe Research.

Doug Leggate: Obviously, there’s a lot of attention on this Harkey shale issue. So I think, Blake, you’ve given a fairly thorough explanation as to what happened, but I just want to put a bow on this. So basically, this was a cementing issue. It sounds like — that sounds like it’s temporary. It doesn’t sound like it’s getting any read through, but what does it mean for your view of inventory debts as you think about your future development plans. My follow-up is on the change. Obviously, the change in activity is somewhat transitory, I guess, given everything that’s going on. But you did just lay out a 3-year plan a couple of months ago, that laid out sort of 5-plus percent oil growth. So I’m curious how does the thinking on that change and the associated capital that goes along with it? And I’ll leave it there.

Tom Jorden: Yes, Doug, I’m going to start it and then Blake will add any comments. A lot of elements to that question. I’ll take them in reverse order. Our 3-year plan is intact. We don’t see any meaningful change to our 3-year plan. I’ll also say we don’t think this impacts our long-term inventory. We think this is a local mechanical issue that’s fully solvable. We have a couple of remediation steps underway. It’s one that, as Blake said, we think is associated with some shallow saltwater disposal that is somewhat unique to the eastern Culberson County. But I’m going to just also say, Doug, we’re a science-driven organization. And much as I’d love to say we walk on water, we occasionally have operational problems and when we saw this, we said, look, we need to understand this fully.

And so we shut this down. While we studied it further, we ran — we collected a lot of data, but we said we really need to understand this before we move forward with this program. We’ve got that data in hand. We think we understand the phenomenon. And we — we’re going to tell you what we know and tell you what we don’t know. But right now, we’re pretty optimistic that this is a mechanical operation that is solvable with a combination of revised pipe design and cementing program. Blake, do you want to comment on that?

Blake Sirgo: Yes. I’ll just say, Doug, coming into Windham Row, we had drilled and completed over 30 successful Harkey wells in Culberson County. We use the same wellbore designs and see many jobs. We always have. We thought we were well calibrated. Sometimes the oilfield still surprises us. And so that’s what we’re dealing with here. It’s not a ubiquitous issue. We have several wells performing just fine. Our teams are hard at work solving this. We have other tools in the toolkit. We have different cement jobs. We have different wellbore designs. We’re deploying all those right now. And we will figure out the optimal solution, and we will fix this, and we will move forward.

Operator: And your next question comes from the line of Betty Jiang with Barclays.

Betty Jiang: I appreciate all the color on Harkey earlier. But I do think it’s important just to flesh out sort of the potential impact to the future development. So if you’re focusing on the future roles just on Wolfcamp, are you going back to the Harkey on those roads? And does that have any impact on the mix of wells if we look out into 2026.

Tom Jorden: Yes, Betty, 2026 is a long ways away. Our expectation, I’ll just say this, is that we remediate this issue and we get back to restoring our Harkey program as it was before we paused. Now we’ve talked in the past that we really think co-development is preferable to overfill, but the time lapse between when the Wolfcamp comes on production and when the Harkey comes on production is a critical variable. And as we currently see it, we think we’ll be back to completing and drilling these Harkey wells in months, not years and that overfill effect will not be significant. So we — this is a mechanical issue but not a strategic issue in terms of how we’re going to prosecute. We don’t think we’ve lost inventory. We think we just appropriately paused while we figured this out and come back with an approach that will allow us to develop these Harkey wells prudently, and without this water. But Blake, do you want to comment on that?

Blake Sirgo: Yes. I mean I would just echo what Tom said there. I mean we think this is a prudent step to adjust our mechanical process on how we construct well bore, cement wellbores, whatever the optimal solution is. In the meantime, we’ll be executing of our Wolfcamp program. We have a long history in the Upper Wolfcamp and Windham Row has been very strong, excellent performance. We expect that to continue. And meanwhile, all our row efficiencies are some fracking our electric crew, everything continues as is. So from a capital efficiency standpoint, it’s actually slightly better in the near term just because of the productivity of the Upper Wolfcamp, but we are still very focused on solving the Harkey and getting back to the original program if possible in vetting that out.

Betty Jiang: I really appreciate that. And then just on the production guide, the full year guidance will imply a fairly big ramp from second quarter, maybe to the mid-170s level in 4Q. Could you just help us get more comfort on that trajectory, the timing of the wells and what type of risking is being done within that guide?

Shane Young: Yes, Betty, Shane here. I’ll speak to that again. And so look, I think you’re right. And these all hold together in terms of the quarterly guidance for the annual guidance, et cetera. And we do anticipate seeing substantial sequential step-ups in production through the course of the year. And if you look at the TIL guidance that we provide for the second quarter, you’ll see it’s meaningfully up from where we were in the first quarter, which will lead to the very strong third and fourth quarter production.

Operator: And your next question comes from the line of Nithin Kumar with Mizuho.

Nitin Kumar: Tom, I want to start off a little bit broader. You mentioned in your opening remarks about the rifle shot and the guided missile. You and one of your peers today have cut activity in response to the current uncertainty. The current administration ran on an agenda of drill baby drill. So I’m just trying to understand, from your perspective, how long do you think this weak environment could continue between the demand that has been destroyed a little bit and then the supply that’s coming on.

Tom Jorden: Is that all you?

Nitin Kumar: I just want to —

Tom Jorden: No, no. You asked, and this is not just my view, but I think the view of Coterra. I’ll just say this, we’re a little over 100 days into this new administration, and good lord. There’s been a tremendous amount of volatility introduced. Whether we’re talking about in the oil markets or tariffs in our relations around the world, all of these converge on forecast for our oil price. The President is trying to do a lot of difficult things upfront and the White House is in a hurry. And we have some sympathy for that sense of urgency. But I’ll just say this, I think the White House has been fairly consistent that they want low oil prices that, that is a bit of a turbocharge to the economy, and we’re expecting that to continue.

We think that certainly a lot of what’s going on with OPEC is perhaps all tied together in concert with what’s happening in the Middle East broadly in some of these conflicts. And so we’re prepared for this to last a while. We’re hopeful that these tariffs get resolved and that the threat of recession is lifted. But our experience tells us that we can’t run our program on hope and we better be prudent and make adjustments accordingly. The thing we’re very grateful for is that this isn’t a situation that shuts our capital program down. It just redirects it. And we have some really attractive gas opportunities we could pivot to. So we are battening down the hatches, expecting this to last for a while and answer to your question.

Nitin Kumar: Great. And then — and I know it’s a difficult question. My second question is around cash returns and maybe Shane can take it, but you’ve talked about returning at least 50% or more of free cash flow obviously, buybacks were second half weighted. You talked a little bit about the balance sheet. If commodity prices do weaken from here, how do you prioritize between buybacks and debt reduction?

Shane Young: Yes. No, I appreciate the question. And we for the plan and rolled it out back in February, we talked about sort of the ability to do it all. And since then, prices come in a little bit. And if you look at Page 10 in our deck today where we talk about free cash flow and how much it is, we still have the ability to do it all, so to speak. But to be really clear, in 2025, our priority is going to be debt repayment. And we’re not going to compromise that. That doesn’t mean that there’s not going to be repurchases. We can be opportunistic, and we will be back-end weighted. But if you look at 2024, we returned 90% of cash flow to shareholders. ’23, we returned 76% of cash flow to shareholders. Why were we able to do that? Because we had low leverage. And we believe that having low leverage is an enabler, and we’re dead set focused on protecting our long-term shareholder return objectives. And we think the best way to do that is to reduce debt.

Operator: Our next question comes from the line of Arun Jayaram with JPMorgan.

Arun Jayaram: I just wanted to get an update on the Barba Row, and how does the issues that you’ve experienced on the Harkey program impact the development program there. I believe the original plan was to do 20 Wolfcamp wells and 8 Harkey wells. What is the status of perhaps of those 8 ARC those in the original plan?

Michael Deshazer: Arun, it’s Michael. Yes, you’re correct. We have 20 Wolfcamp wells in at Harkey. We were — we have completed 2 of the Harkey wells and there are 6 additional Harkey wells that we’re going to duck currently, and we will update you on those as we move forward. But at this point, they’ve been removed from the current frac schedule, and we’ll proceed with the Wolfcamp completions.

Tom Jorden: Yes. And I would just kind of add on to that, given the status of those, those do come back into the program, they’re going to be highly capital efficient, just given that a portion of that capital has already been put into the ground.

Arun Jayaram: Got it. That’s helpful. And just maybe just a thought on how does the reduction in your rig count in the Permian. How is that impacting your thoughts on the 3-year program? Obviously, as Betty mentioned, the second half run rate for oil will be higher just given the shift to the Wolfcamp from the Harkey. But how is that help us square away the reduction in CapEx on the Permian and just maintaining that 3-year program.

Tom Jorden: Yes. So I can take that. So first, we’ve reduced on — in the Permian, $150 million, $120 million D&C. So it’s we’ve gone from 10% to 7% in the second half of the year. So it does not alter the overall outlook over the 3-year window. We believe within the parameters that we’ve set out, which is $2.1 billion to $2.4 billion of capital over the next 3 years — each year over the next 3 years that we still got the ability to do 5% plus oil volume growth and 0% to 5% BOE growth over that period, even with the changes that we’ve talked about today to the second half of 2025.

Operator: Your next question comes from the line of Neil Mehta with Goldman Sachs.

Neil Mehta: Yes. Thanks for all the color here. Tom, we’ve talked a lot about oil today. Just curious on your perspective on natural gas, you are taking — starting 2 rigs here in the Marcellus. Maybe talk about what your priorities are for the Marcellus plan for the balance of the year and how that ties into your macro view for gas?

Tom Jorden: Yes. Thank you for that. I just want to remind the listeners that we produce just [indiscernible] under 3 Bcf a day of natural gas. So the increase in natural gas outlook is wonderful, but the increase in natural gas prices is a remarkable turbo charge to our cash flow and provides the kind of resilience that we’ve talked about. We are getting back to work in the Marcellus. We’ve made tremendous progress redesigning our Marcellus program. We’ve talked about that on past calls. But the net result is a more efficient way to handle water, the flexibility to be able to go to 0 activity or a full steam ahead, longer laterals. And it’s just been a remarkable redesign that’s also resulted in much lower cost structure. So go forward, I anticipate our Marcellus program to be back to a growth profile and how aggressively we grow is a function of all the moving parts that we’ve talked about in this call.

But we are really encouraged by the economic and reservoir performance of our natural gas assets, both in the Marcellus and in the Anadarko.

Neil Mehta: And then Tom, I mean, it’s been a couple of years now, but there has been discussion points about the depth natural gas portfolio as you’ve drilled out a lot of Northeast PA, maybe you can respond to that viewpoint about depth of inventory. Do you feel like you have the organic position that you want here now that you’ve done the Frankly Mountain deal on the oil side, does it make sense to think about gas M&A? Just your perspective in addressing that debate that’s out there.

Tom Jorden: Well, we think about that throughout our portfolio. I mean if you ask me if we have enough inventory, my answer to that is determined about a decade ago, it’s going to be no. I’m an exploration, that’s at heart. But as we show on Slide 11, we have about a dozen years of inventory at our current run rate and that production base that underpins that. That’s inventory. But with that production base, we’re really nicely positioned, but we’re always want to be opportunistic, whether it’s oil, natural gas or what have you, we’re built to last. And I think we’re going to be a survivor here. So inventory is important to us. We think we’re — we don’t have a problem to solve, but we’re going to be opportunistic. And that’s not the telegraph that we — like I say, we’ve got really solid plans and there’s not a problem to solve there.

Operator: And your next question comes from the line of David Deckelbaum with TD Cowen.

David Deckelbaum: Maybe just — I wanted a clarification on just the ramp in the second half of the year with the Wolfcamp wells coming online. Does the guidance presume that, that 5,000 barrel a day impact in the second quarter from the Harkey wells, does that come back as a 5,000 barrel a day contribution into 3Q and 4Q?

Shane Young: Dave, it’s Shane here. No, it doesn’t. It doesn’t assume that it comes back. Obviously, Blake walked through all the things the team is doing to get us to a different outcome, a better outcome than that, but the assumption that we’re talking about in terms of the substantial, sequential step-ups that we see in production in the back half of the year does not at all rely on those volumes coming back.

Tom Jorden: Yes. We’ve taken — as I said in my opening remarks, we’ve taken a very conservative approach. We think we’re going to bring those volumes back. But our current plan we’ve just taken them out. And we’re looking at a fairly significant production growth ramp during the course of the year, and we’re confident, hopeful and our technical analysis tells us that this problem is fixable and that a lot of those volumes are coming back.

David Deckelbaum: Appreciate that, Tom. And just my second question, you guys highlighted the flexibility that you have with your asset base and talked about, I think, the 15:1 oil to gas price ratio currently at strip pricing, and you’re still seeing sort of the coincident 50% plow back in terms of CapEx. But as you enter in the next couple of years, I think you guys reiterated the 3-year outlook, but if you go back to that guided missile analogy, if that oil to gas price ratio holds as we enter into next year, should we presume that there’s more reallocation from oil to guest weighted assets?

Tom Jorden: Well, what you ought to presume is that we get up every day and make the best financial decisions in the interest of our shareholders that we think it’s prudent. And we — I’m hesitant to even use the word 3-year plan. It’s a 3-year outlook of what we could execute if current conditions were to hold. And if current conditions don’t hold. I think it’s our responsibility, not just our opportunity but responsibility to say to our owners that we will readjust as conditions warrant. So the beauty of it is we have amazing flexibility. I mean, when we look across our landscape right now, we could barrel ahead at $50 oil and continue to invest in our oil assets and the returns are not bad. I mean, they’re certainly better than if we rewind not too many years ago with anything we were experiencing.

But we’re making these steps because we’re concerned about future weakening in oil prices. And so it’s a remarkable position to be able to say, look, we could invest in oil. We can invest in gas. We’ve got the NGL revenue. And everywhere we look in our portfolio, we have opportunity and not barriers. We’re just trying to adjust to the macro condition as we think is appropriate, and that’s what we’re going to continue to do.

Operator: And your next question comes from the line of Scott Gruber with Citi Capital.

Scott Gruber: Yes. Just wanted to come back to the Harkey production you said with the cement remediation you’re working to bring those volumes back, but it’s not in guidance. So what’s the reasonable expectation for when those volumes could come back if the remediation work is successful?

Tom Jorden: Yes. We don’t have a firm timeline on that just due to the nature of the workovers. These workovers will take months. It’s a pretty big campaign to work through all the wells. Like we discussed, we have multiple things. We’re trying to make sure we get good isolation. So it’s months out, not weeks out.

Scott Gruber: Got it. And I appreciate you guys are constant looking to adjust given changes in prevailing conditions. But curious just about kind of early thoughts on what would happen to the ’26 if oil follows the curve here in the high 50s. Do you end up maintaining 7 active rigs in the Permian? And if you maintain 7, what does that mean for Permian tills in ’26 in Permian production?

Tom Jorden: Yes. Let me say that if oil were covering around 60 — you said high-50s, low-60s. We have the opportunity to make investments in our oil assets. I mean it’s not like that program is shut down. It’s not a question of what the number is. It’s a question of why the number is — is it — does it move up a little bit because OPEC decided to pause their reinstate their curtailments for a quarter and that it could happen again 3 months down the road or does it happen because this tariff situation is resolved. We’re back to normal trade relations. The world economy is growing and demand increases. I mean, there’s all kinds of moving parts here. Right now, we’re pausing our oil program — pausing, I’d say we’re relaxing slightly because we’re concerned that oil prices could further weaken.

I hope we’re wrong on that. But our experience tells us that when you see these events and you see the possibility be prepared for the worst-case scenario, and that’s kind of where we are. I hope we’re overreacting on several of these issues. But that’s — you can use us being conservative and that’s probably fair.

Operator: And your next question comes from the line of Josh Silverstein with UBS.

Josh Silverstein: So you’re moving some CapEx over to the Marcellus. I’m wondering if there’s any sort of limit into how much more capital you want to put there? Maybe is there not enough pipeline capacity for volumes to grow? Or is there some sort of trigger you’re looking forward to continue to push that additional $50 million over.

Tom Jorden: No, there’s really not a significant limit. But the constitution pipeline has been in the news lately. And yes, I just want to remind the listener that Constitution Pipeline is originally configured, originates in our field in Northeast Pennsylvania and goes into the New England market. And we’re watching and participating in that conversation seriously. And we would — if that were to go the expectation is that we would make a commitment to deliver long-term volumes into that line. And so that’s kind of coloring what we want to do at this point in time. We think that issue will resolve itself here in the next few months. But we’re looking at that as a potential future opportunity for growth in the Marcellus.

Josh Silverstein: All right. And then just on the pricing side, you guys already have some power exposure. I think it’s high single digits for the Marcellus. Given that you guys already have this, I’m curious if you can give us kind of a backdrop as to maybe if you would add some more a little bit more about what’s happening within that power pricing for the Marcellus for you guys?

Blake Sirgo: Yes, Josh, this is Blake. We’re always looking for more power pricing. The 2 deals we have in Marcellus are excellent deals. They’ve paid very well over time. They’re difficult to replicate so I think that’s really the challenge we’ve been after. We’re really interested in particularly Greenfield projects where weakened capture upfront the long-term power strip that we’re hoping to get into our gas portfolio. There are a few opportunities in the Marcellus, but we’re looking at quite a few opportunities in the Permian as well. I think the market is waking up to the disadvantaged Waha molecule, and then it’s a great place to generate electrons. And so we’re looking at many different ways to participate in that.

Operator: And your next question comes from the line of Kalei Akamine with Bank of America.

Kalei Akamine: Sorry I was on mute. I’ve got a different question on the Harkey here. Kind of looking beyond the water issue, where the wells long enough to get a read on the productivity and how it compares to the Wolfcamp.

Tom Jorden: Yes. What we see in the Harkey that one of the things that gives us a high degree of confidence that this problem is solvable in that it’s not on every well. We’ve got a couple of drilling spacing units that look like they’re performing just fine and making oil volumes at — are within a reasonable boundary of expectations. So this — yes, we think the laterals are long enough. As I said in my opening remarks, we are highly confident that this is not a reservoir issue per se in this not a spacing issue. It’s not an overfill versus co-development issue. It’s a mechanical issue near wellbore fixable near wellbore. And that’s our — we have an overwhelming a bounty of evidence that’s suggesting that, but we’re a company that’s — we focus on results and we want to see the results of these remediations and we will communicate that along the way.

Kalei Akamine: For the follow-up, kind of following up on one of the earlier questions here. If this is the new program, if this program is a new template kind of point forward, can you give us a sense of what the run rate capital and the oil plateau could look like. And if oil were to decline, would you still expect wet gas production to increase?

Tom Jorden: Yes. I’ll say, we don’t expect oil to decline, but if I’m understanding your question properly, we see a good runway as our 3-year plan that outlined of reasonable growth in our assets broadly. Shane, do you want to cover the —

Shane Young: Yes. I mean just — I understand the question correctly. I mean, I think if we were to stay on this path into the future, we would go well through the end of this decade in terms of the opportunity set that we have there, even if it was this past.

Tom Jorden: Yes. We’re not — we’re holding to our 3-year plan, as outlined with the changes that we’ve discussed in this call. I want to be really clear with everybody on that. We’ve got a very fulsome model that shows that, that 3-year plan is reaffirmed.

Operator: And your next question comes from the line of Matt Portillo with TPH.

Matt Portillo: Tom, maybe just a question around maintenance capital. Given the outlook for the second half of 2025 with production potentially in the mid-170-ish range. Could you give us an update on what you think you might need to spend to hold oil volumes flat over a multiyear period? Just trying to get a sense of your maintenance capital program.

Tom Jorden: Yes, I’m going to let Michael take that one.

Michael Deshazer: Yes. I appreciate the question. So as we’re looking at the current program for 2025 and looking into the out years, as we’ve discussed, our 3-year plan has oil growth. So obviously, the capital levels that we’re currently at can be shed. We can remove capital to maintain that oil production. We also have oil growth coming from both the Anadarko and the Permian in most of our plants. So it’s important to think about that combination because we’re funding in both programs. But in general, right now, we see our oil growth. We have to think about where are we going to keep the oil production flat at. And right now, if we look at our 2025 volume of 160,000 barrels a day if we were to keep that flat, we would be somewhere around 15 billion to 16 billion between the Anadarko and the Permian. Obviously, the Marcellus capital is disconnected from any of that oil growth because it doesn’t produce any oil.

Matt Portillo: It would be for a multiyear period at which you could hold it flat, not just a single 1-year hold.

Michael Deshazer: That’s correct, yes. So that would be if we were to just go to a maintenance capital for a kind of 3-year period.

Matt Portillo: Perfect. And then just a follow-up question. I know your programs are extremely flexible. I was curious how you’re thinking about the returns in the Anadarko in a strip price environment versus the Permian program? And is there an opportunity heading into 2026 if we stay at strip that you could further high grade your development between the 2 basins?

Tom Jorden: Well, we high grade our development all the time. So yes, we have an opportunity. But it’s really a function of that oil gas ratio and also NGLs, natural gas liquids. We’ve got some really nice Anadarko projects for which gas and natural gas liquids are combined to make the dominant revenue stores. So it’s a function of the oil gas ratio. We’ve talked about when we’re down 15:1 and lower, it starts getting to be a pretty serious horse race among our 3 of our basins.

Operator: And your next question comes from the line of Derrick Whitfield with Texas Capital.

Derrick Whitfield: A slight twist on David’s earlier question referencing Slide 4, this forward oil to gas ratio were to persist, would it change your view on the areas and intervals you develop in the Delaware over your 3-year forecast? And I’m primarily thinking of Culberson with this question?

Tom Jorden: I mean, no. I don’t think it really changes our where we go into Delaware. All 4 of our operating areas, Eddy, Lee, Reeves and Culberson County have really nice competitive environments. Now Culberson tends to be a little gassier, which is — which actually is good for our operating cost and our productivity. But if we had a little stronger Waha price, that might have an impact. But as we look out at the strip, I don’t think that will really be a significant flex of capital within the Permian.

Derrick Whitfield: Great. And as my follow-up, regarding your contingency planning comments in your prepared remarks, what price do you see as the next tipping point in all activity, assuming current service costs, and that’s to assume we’re going lower in price, clearly.

Tom Jorden: I think we were seriously looking at the price below $50, you’ve seen their tipping point.

Operator: And your next question comes from the line of Kevin MacCurdy with Pickering Energy Partners.

Kevin MacCurdy: Looking out to the back half of 2025, what is the rate reduction due to your DUC backlog by the end of the year? And do you have to manage that operationally as you enter into 2026?

Michael Deshazer: Kevin, this is Michael. No, we move into 2025 with a nice DUC inventory. So even as we’re swapping out from Harkey into Wolfcamp. We’re not seeing any major issues on our frac lines. Obviously, our rig count is long term related to our frac fleet count. And so dropping down to 7 rigs, if that were to remain unchanged, holding the third frac crew consistently would be difficult. That is shown in our deck that there might be more spot work late in the year if we hold that 7 rigs. But that’s not a problem for us operationally. We think that there’s ample capacity in the frac market right now, and so that’s not necessarily a driving force for us.

Tom Jorden: Kevin, we do a lot of planning and included in those plans as a look at what our DUC inventory looks like, both not only in terms of wells, but number of projects, number of pads and both of those are really important in terms of operational flexibility. And so that’s a real important planning. I don’t know if you want to call it an input or output, but it’s an important planning consideration. And then in the MBU, our DUCs are configured often to hit winter pricing. And so it’s just a point of active consideration wherever we are.

Kevin MacCurdy: I appreciate that. And as a follow-up, just a clarification on the free cash flow for the remainder of the year, the uses of free cash flow to say. Will you pay off the term loan first and then buy back shares? Or can you do them concurrently. And are we reading it right that the 50% shareholder return is a multiyear goal and you may not get there in 2025.

Tom Jorden: Yes. So look, just as we’ve done the last couple of quarters, we can and likely will continue to do both in a parallel way. It’s just what’s the waiting is one front-end loaded, one back-end loaded. I don’t know that we necessarily have to make a choice, one or the other as we go along. There’s a lot of different considerations that go into the timing and amount of those buybacks. But no, we’ve not shut down the buyback program by any means. We’ll continue to be opportunistic as we go through the rest of the year, but we’ll also be focused on what is the cash flow profile look like for the rest of the year as well. And certainly, yes, if you look back over time, as I said earlier in response to the question, we’ve historically been well above 50%.

Again, we’ve been 90%, we’ve been in the mid-70s at various points in time. Why were we able to be there? We’re able to be there because we had low leverage. And so we think the getting the notes paid down early on really helps facilitate stability of shareholder returns for the long term.

Operator: And I would now like to turn the call back over to Tom Jorden.

Tom Jorden: Yes, I want to thank everybody for a series of great questions. I’ll just say in closing, personally, I’m deeply proud of the way our organization has responded to not only this volatile time, but also this operational issue we’re facing. I think we’re on the right track. We have a solid plan, and we’re going to perform in surprise to the upside. But thank you very much for your attention this morning.

Operator: This concludes today’s conference call. You may now disconnect.