Coterra Energy Inc. (NYSE:CTRA) Q4 2024 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q4 2024 Earnings Call Transcript February 25, 2025

Operator: Hello, and welcome to Coterra Energy Inc. fourth quarter 2024 earnings conference call. Please note that this call is being recorded. After the speakers’ prepared remarks, there will be a question and answer session. If you’d like to ask a question during that time, thank you. I’d now like to hand the call over to Dan Guffey, Vice President of Finance, Investor Relations and Treasury. You may now begin.

Dan Guffey: Thank you, Ellie. Good morning, and thank you for joining Coterra Energy Inc.’s fourth quarter 2024 earnings and 2025 outlook conference call. Today’s prepared remarks will include an overview from Tom Jorden, Chairman, CEO, and 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 to answer questions. 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 were 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 welcome to everyone joining us this morning. We’re pleased to discuss our fourth quarter and full year 2024 results, our plans for 2025, and our updated three-year outlook. First, Coterra had an excellent fourth quarter. We achieved production levels above the high end of our guidance range for oil and natural gas, with capital expenditures coming in near the low end of our guidance. We returned 61% of our free cash flow in the fourth quarter through dividends and share buybacks. For the full year 2024, we returned 89%. Most importantly, we generated outstanding results on our capital investments in 2024, achieving financial returns that are robust, durable, and repeatable. I want to commend our entire organization for delivering these exceptional results.

Our 2025 capital plan aligns with the preliminary guidance we provided during our November announcement regarding the Franklin Mountain and Avant acquisitions. In 2025, after folding in the newly acquired Permian assets, we expect to run a consistent and highly capital-efficient program across each of our three operating regions. As always, we maintain flexibility to pivot and reallocate capital as conditions warrant. We are closely monitoring gas markets and remain prepared to modestly accelerate our Marcellus program if the current positive outlook were to persist through mid-year. This acceleration could add $50 million to our 2025 capital program, allowing Coterra to deliver incremental natural gas production volumes by early 2026, in time to capture winter pricing and respond to projected demand increases.

Although our 2025 plan includes significant oil investments, we also have flexibility if oil markets were to wobble. Rest assured, if we need to adjust our capital plan during the year, we will do so thoughtfully and explain it thoroughly. Flexibility is the coin of the realm. Regarding the Franklin Mountain and Avant acquisitions, we successfully closed both transactions in late January and are actively integrating these assets to optimize our capital and operational efficiency throughout our Permian operation. I want to congratulate our team for successfully completing these transactions and acknowledge the professionalism of the Franklin Mountain and Avant teams during the final stages. We also updated our three-year outlook in yesterday’s release.

Two years ago, we were cautious in releasing our initial three-year plan because of our experience in seeing others’ three-year plans evaporate quickly with changing conditions. At that time, we communicated that our three-year outlook was not a definitive plan but a guide to what we could achieve under prevailing conditions. Since then, we are pleased to have delivered and exceeded on our rolling three-year projections. Our updated three-year outlook released last night positions Coterra for industry-leading profitable growth, capital efficiency, and reinvestment rates. Together, these stem from our outstanding assets, high-performing organization, and commitment to capital discipline. The team continues to be laser-focused on maximizing return on capital and increasing per-share value for our owners.

With that, I will turn the call over to Shane for further details.

Shane Young: Thank you, Tom. Thank you, everyone, for joining us on today’s call. This morning I’ll focus on four areas. First, I’ll discuss highlights from our fourth quarter and full year 2024 results. Then I’ll provide production and capital guidance for the first quarter and full year 2025. Next, I’ll provide a new and updated three-year production and capital outlook for 2025 through 2027, incorporating our recent acquisitions. Finally, I will discuss our shareholder return program and outlook for deleveraging. Turning to our strong performance during the fourth quarter. During the fourth quarter, oil and natural gas production each came in over 3% above the high end of guidance. We saw outperformance in new wells that came online in both the Permian as well as our new wells that came online in December in the Marcellus.

Turning lines during the quarter were in line with expectations totaling just under 35 net wells, with the Permian, Anadarko, and Marcellus all near the midpoint of guidance. Additionally, we brought back all of our curtailed volumes into Marcellus in early December. Free hedge revenue was over $1.4 billion, with oil being right at 50% of total revenue during the quarter. We reported net income of $297 million or $0.40 per share, and adjusted net income of $358 million or $0.49 per share. Incurred capital in the fourth quarter was just above the low end of our guidance range with lower than expected outside operated activity as well as lower completion and post-completion costs. Discretionary cash flow for the quarter was $776 million and free cash flow was $351 million after cash capital expenditure.

For the full year 2024, Coterra generated outstanding results. Total equivalent production beat the high end of our guidance range, coming in at 677 MBOE per day. Oil production for the year exceeded the high end of our initial guidance by about 4%, growing organically 13% year over year. And natural gas production was in line with the high end of our initial guide. This outperformance was driven by a combination of beeps on an and to a lesser extent accelerated timing. Capital costs were just above the low end of the guidance range, coming in at $1.76 billion, driven by better than expected service costs and lower activity in the Marcellus and Anadarko basins. This represents a 16% decrease in capital spending year over year, so we continue to see greater capital efficiency across our program.

Cash operating cost per unit was near our guidance midpoint, totaling $8.66 per BOE for the year. Looking ahead to 2025, we’ve already made significant progress integrating our newly acquired Permian assets into the Coterra program. Both transactions closed in late January, and therefore our 2025 results will only reflect the partial month of January production from each of those assets. During the first quarter of 2025, we expect total production to average between 710 and 750 MBOE per day. Oil is expected to be between 134 and 140 MBO per day, and natural gas is expected to be between 2.85 and 3 BCF per day. Regarding investment, we expect incurred capital in the first quarter to be between $525 and $625 million. For the full year 2025, we expect incurred capital to be between $2.1 and $2.4 billion as we increase activity and capital in the Permian Basin with the assets from our recent transactions.

This range is consistent with the 2025 preview released in November, but with a few changes. Specifically, Permian spending is lower, reflecting additional expected cost savings as well as capital synergies on our acquired properties. While we won’t realize all of these in 2025, we expect to achieve run-rate synergies on these new assets of roughly $50 million. This savings is not from reduced activity, but rather savings on expected activity relative to cost achieved by the previous operators. At the same time, we’ve added activity and capital in the Marcellus, reflecting improved natural gas fundamentals and a lower cost structure. We have the flexibility, if warranted, to increase our investment later in the year while staying within our guidance range.

This additional capital will allow us to bring on incremental volumes next winter and stabilize our Marcellus production volume levels. Also consistent with our 2025 preview, we expect total production for the year will average 710-770 MBOE per day, and oil is expected to be between 152 and 168 MBO per day, or 47% higher year over year at the midpoint of oil guidance. Natural gas is expected to be between 2.675 and 2.875 BCF per day, relatively flat year over year at the midpoint. This delivers just over 1 TCF of gas on an annualized basis, providing significant leverage to an improving natural gas market. Having only a partial month of January on the new assets impacts full year 2025 production by a little over 4 MBOE per day relative to the guidance we previewed in November, which assumed an illustrative January 1, 2025 closing date.

Reflecting on our new three-year outlook, as we have done over the past several years, yesterday, we announced our new three-year outlook for 2025 through 2027. We believe this is a robust, capital-efficient plan that delivers consistent, profitable growth for our shareholders. We anticipate we can deliver 5% or greater oil volume growth over this period and 0-5% per BOE growth by investing between $2.1 and $2.4 billion of capital per year. These growth rates include legacy Coterra organic growth in 2025 and include our recent acquisitions for 2026 and 2027. This outlook reflects increased capital efficiency, and it’s designed to afford Coterra the flexibility to reallocate capital between our assets. We believe this outlook has an attractive level of reinvestment, delivers meaningful free cash flow to underpin our shareholder returns and deleveraging goals.

Turning to shareholder returns and deleveraging. Last night, we announced a $0.22 per share dividend for the fourth quarter, increasing our annual base dividend by 5% to $0.88 per share. This remains one of the highest-yielding base dividends in the industry at over 3%. Management and the Board remain committed to reviewing increases in the base dividend on an annual cadence. During 2024, despite soft natural gas prices and their impact on cash flow, Coterra continued to execute on its shareholder return program by repurchasing 17 million shares for $464 million at an average price of approximately $26.41. In total, we returned 89% of free cash flow during the year, or $1.1 billion, through our repurchases and dividends. During 2025, Coterra expects to prioritize deleveraging, and under current conditions, we expect to repay our $1 billion of term loans.

We are focused on quickly getting our leverage back to around 0.5 times net debt to EBITDA. Coterra is committed to maintaining a fortress balance sheet that is strong in all phases of the commodity cycle, enabling us to take advantage of market opportunities and protect our shareholder return goals. Assuming our current outlook, we would expect to return 50% or more of annual free cash flow to shareholders in 2025 with a combination of our healthy base dividend and our share repurchase program. In summary, Coterra’s team delivered another exceptional fourth quarter and full year of high-quality results, both operationally and financially, and across all three business units. We’ve hit the ground running during the first few months of the year and expect to deliver solid first-quarter results in 2025, which should set the foundation for full-year 2025 and beyond.

With that, I’ll hand the call over to Blake to provide additional color and details on our operations.

Blake Sirgo: Thanks, Shane. As we close out 2024 with another great quarter and lay out our new plan for 2025, we continue our mission of consistent improvement. Whether it’s our execution in the field, the efficiency of our operations, or the productivity of our assets, we are striving for consistent improvement on all fronts. This is a shared mission from the Houston office to the Wellhead, to constantly chase improvement and never settle for the status quo. The 2025 plan we have laid out sets several new bars with the most Permian activity we’ve ever deployed, including a full year of Culberson Simulfrac, a consistent program in the Anadarko, and a return to the Marcellus, where we are armed with a new record low-cost structure.

As Shane noted, our 2024 capital came in on the low end, driven by cost reductions and efficiencies, while our production came in above the high end, thanks to improved cycle times and strong asset productivity. Importantly, Coterra operations executed on several key milestones in 2024. We deployed and executed on our first grid-powered electric simulfrac in Culberson County. We partnered with our frac providers to develop new pumping strategies and automation, which set records in pumping hours across our fleets. After years of hard work and careful planning by our Marcellus team, we drilled and completed wells in the Dimock Box, which could rank as one of the best Lower Marcellus developments in field history. In conjunction with planned gas curtailments, we were able to bring these wells online to full rate in December, capturing peak pricing for the winter months.

We accomplished all this while improving upon our great safety performance in the field. Consistent improvement defined 2024 and now becomes the foundation for our 2025 program. We entered 2025 in the Permian running three frac crews and 13 rigs. We plan to run three crews all year and reduce to 10 rigs as we bring our efficiencies to bear on our new assets. Our 2025 Permian program is forecasted to cost $960 per foot, down 6% from 2024. This lower cost structure is driven by efficiency gains we made throughout 2024, along with new competitive service contracts. When pairing our fully burdened Delaware cost structure of $960 per foot with our strong asset productivity, we are projecting another strong year for capital efficiency. In the Permian, our teams have been hard at work integrating our new assets into our Delaware office machine.

They have taken on the new assets and are already finding ways to enhance our efficiencies and returns. By optimizing the new assets under one consistent frac line, we are able to drop multiple rigs without sacrificing any planned frac activity or production. Additionally, our teams have been hard at work optimizing frac designs, pad layouts, and directional programs, which, when combined with new service contracts, reduces 2025 capex by 10% per foot, or approximately $50 million compared to the previous programs. In Culberson County, we plan to run this simulfrac crew consistently all year as we continue to prosecute our road developments. Our initial 57-well development of Wyndham Row is now complete. The completion of Wyndham Row represents a significant milestone for Coterra.

In total, we invested $500 million in gross capex and completed the project ahead of schedule, with final costs coming in at $864 per foot, which is $10 per foot lower than we projected. These wells have been coming online over the last several months, with our first three months of cumulative production exceeding expectations. We have already begun the next two row developments, the 28-well Barbara Row and the 62-well Bowler Row, both of which will co-develop the Upper Wolfcamp in Harkey. Culberson County road developments are some of the largest and most efficient projects in the shale patch, and you can expect many more from Coterra in the coming years. Turning to the Anadarko, we are building on the consistent activity over the last few years, which continues to improve our cost structure.

Our 2025 program in Anadarko is forecasted to come in at $1,070 per foot, down 18% from the previous year. We are excited to bring on our first three-mile developments in the Anadarko in 2025. Lower cost and a good mix of liquids and gas inventory continue to make our Anadarko portfolio an attractive place to invest. In August of 2024, when facing depressed in-basin pricing, we dropped all rigs into Marcellus. We challenged our Marcellus team to attack our cost structure and improve our capital efficiency to help us restore activity. The teams delivered by providing us with a highly efficient plan in 2025 that is anchored by a record low-cost structure of $800 per foot. This dramatic reduction in cost structure is anchored by structural changes and includes the reengineering of upcoming projects, which increased our average lateral length by 60% compared to the prior plans.

This long lateral program, combined with lower service costs, structurally lowers our breakeven costs and generates a strong 2025 program that we are excited to invest in. Our current plan calls for two rigs starting back up in April, as well as distributed frac activity throughout the year. We also have on-ramps to increase activity throughout 2025 should gas markets continue to firm up. On the marketing front, we continue to work hard in maximizing our gas sales portfolio. A strong winter has pulled down storage below the five-year average, bolstering the domestic indices we pull into. The ramp of Gulf Coast LNG has begun with record flows in February. We continue to explore potential export deals to add to our existing international portfolio.

We are seeing new calls on natural gas for power generation in the basins we operate in. We are working with power providers and power consumers to see how Coterra Gas can help generate the electrons they require. Coterra is well-positioned and poised to take advantage of this expected power demand across our portfolio. We are excited to announce a highly capital-efficient 2025 plan and three-year outlook, and you can expect we will continue to see consistent improvement in all facets of our business. With that, I’ll turn it back to Tom for closing remarks.

Tom Jorden: Thank you, Shane and Blake. We’re pleased with our continued execution in 2024 and expect to deliver on our goals outlined in our plans. We appreciate your interest and look forward to taking your questions.

Q&A Session

Operator: We are now opening the floor for the question and answer session. Kindly limit your questions to one question and one follow-up. Your first question comes from Arun Jayaram from JPMorgan. Your line is now open.

Arun Jayaram: Yeah. Good morning, team. My first question is I was wondering if you could discuss some of the key lessons learned from the Wyndham Row, including the interplay between the Wolfcamp and the Harkey programs, and just some of the key learnings from that program as you look forward to a couple more projects within Culberson this year, the Barber Row and the Bowler Row.

Tom Jorden: Yeah. Just I’ll take that one. Really came on as we had forecast. We see excellent reservoir performance. Our actual total production is right on top of our forecast. Outstanding results. You know, we still have you are in a data collection analyzing mode. On the need to either co-develop or overfill later. But based on everything we’ve seen, we’re very encouraged and we will continue to co-develop where we can. But it’s still an open question. I’m gonna invite Michael DeShazer to comment on that because he runs our business here in Michael, any learnings from Wyndham Row?

Michael DeShazer: Yeah. Thank you, Tom. Arun, we’ve drilled over 40 Harkey wells in Culberson to date, and we have 30 more planned this year. So the six that we’ve co-developed on the Wyndham Row and the 16 that have been overfilled, that data is still coming in. And like Tom said, we’re gonna be studying that over the next few months. And that will guide our decisions moving forward. But the current plan being to default to co-develop, that’s the path forward for now.

Arun Jayaram: Okay. Thanks for that. In my follow-up, there’s some kinda nuances around the 2025 guide that we’ve gotten some questions on. Could you talk a little bit about, you know, maybe what’s happening in one queue on a sequential basis, and but the broader comment was that it appears that you’re kinda maintaining your guidance that you provided in November, but with one less month called a production from the acquired assets. Am I reading into that right? Is there just some you’re basically maintaining that production guide, but with fewer days, I call it, on the acquired asset. Just wanna clarify that comment.

Blake Sirgo: Yeah, Arun. This is Blake. You’re reading that right. A lot of work’s gone on since the deal announcement, and we’re able to bolster some of the production, which helps overcome that partial month in January. So that’s what you’re seeing there. You also saw on the deck, we were able to pull out quite a bit of dollars in the Permian once our team really got their arms around the asset. Started driving some cost out of it. And we’ve chosen to reallocate some of that to the Marcellus to get activity going there. So that’s really what’s going on. One Q on a sequential basis, it’s just really some noise from the acquisitions on closing time and production. But also some till timing going on normal quarter over quarter type stuff that kinda sometimes it’s a little lumpier than we like, but activity-wise, it’s smooth and straight just like it always is. Great. Thanks a lot.

Operator: Your next question comes from Neil Mehta from Goldman Sachs. Your line is now open.

Neil Mehta: Yeah. Good morning, Tom, Shane, team. Just a couple of gas-related questions in the Marcellus. Looks like you’re gonna be restarting two rigs in April. And so, you know, just can you walk through your thought process of what’s changed from November? And, you talk about potentially increasing capital here in the Marcellus in the second half. If conditions warrant. Can you talk about what are the milestones and goals post you’re watching to say the market’s giving you a signal to accelerate that activity?

Tom Jorden: Well, it’s pretty simple. The returns we’re seeing in our program are now competitive at our current price outlook. We’ve had a nice winter, and, you know, we continue to light candles for increasing cold. Storage is looking much more positive. You know, the situation in Europe is looking interesting from a storage standpoint. We have LNG as, like I said, opening up. So, you know, in many ways, the stars are aligning for constructive pricing throughout 2025 and into 2026. But, you know, we don’t run our program on hope. So we’re not gonna make any decisions we don’t have to make. If we see by spring, mid-spring, that these things are coming to pass, we’ll see how storage ends. We’re prepared to either hold our current course steady or pick up the pace a little bit. But, you know, the very constructive outlook, and we’d like to see that hold.

Shane Young: Yeah. Neil, it’s all driven by the fundamentals, the economics that Tom outlined there. But if we can just to put it in perspective quickly, you know, this increase in activity is from zero to some activity. This is not, you know, I wouldn’t characterize this as a leaning into a gas market as much as just restarting activity based on current fundamentals and economics.

Neil Mehta: That’s great. And then, you know, you talk about the 5% growth for oil on an organic basis and then less of that on a BOE basis. And so you’ve been active in the A&D market here over the last five years. Just what’s your perspective post-Franklin Mountains of the other bolt-ons? Do you feel like you have enough to say grace over or do you expect to continue to be active from an acquisition perspective on the GoFund?

Tom Jorden: Well, we never target acquisitions strategically or tactically. We don’t intend to be in the habit of being a shareholder acquirer. We want to be opportunistic when we see things that make sense for our organization, for our asset mix, and most importantly, for our owners. And that means we acquire them at a reasonable entry price. The Franklin and Avalon assets checked all those boxes, and they were available. And we were really, really glad to pull both of those into our portfolio. You know, we’re already seeing, as Blake said, some operational advantages to having those as we integrate them into the overall program. And look, if we had the opportunity to do that again, we would. But only if the opportunity checked all those boxes.

We’re not out there shopping at any point in time. We’re sitting on a really nice inventory. And we’re not interested in diluting any of our value in the interest of getting bigger. You know, it’s all about entry cost and an organization that can exploit what you have. You know, we’re also looking at organic generation and lease. We’ve got a couple of things underway, none of which we’re prepared to talk about. But things where the entry cost is attractive and there’s a little different risk profile. But, you know, for us, it’s about creating value. And we’ll create value in every direction we can.

Operator: Your next question comes from Nitin Kumar from Mizuho. Your line is now open.

Nitin Kumar: Good morning, Tom, Shane, and team. I want to follow up on the gas side to start with. You highlighted some recent strong momentum in terms of capital efficiencies in the Marcellus, but even including the potential $50 million of acceleration later this year, you’re still well below what you described as your maintenance spend of about $450 million. So and you’re only doing about, you know, 10 to 15 wells, which is a third of what you did last year. So when do you expect to get to sort of a run rate in the Marcellus where you’re holding somewhere about 2 BCF a day flat?

Tom Jorden: Yeah. And then what, you know, Shane made the key point and that is we shut all of our activity down in 2024. And that was the right answer. And, you know, don’t have time in this call to go into it in great detail, but not every operator is able to do that because over the last year or two, we put a lot of effort into water handling in the Marcellus and put Coterra owners in a position where we had complete flexibility there. And so as we restart the program, the restart, what it really does is arrest that decline. Because if you have zero activity in shale reservoirs, we all know they’re high decline, and really puts us on a trajectory of growth. You know, you mentioned that 2 BCF per day target into Marcellus.

We’d be back on our way to that in mid to late 2026, mid to 2027. It would involve returning to something that’s above that maintenance capital you quoted, but look, we’re ready to go there or not depending on conditions. But the conditions today tell us, you know what? These are great investments. They can beat for capital. Plus the rest of that decline and have some incremental volumes ready for winter pricing next winter.

Blake Sirgo: Yeah. And then one other point, I can I take your point on sort of capital versus maintenance capital? Keep in mind, you know, the team as they sort of reengineered the plan up in the Marcellus significantly extended the lateral length of these. So you look at the TILs and the 2025 plan, which we can outline the links a little better on page 21 of the deck we posted last night. You’ll see that they’re meaningfully longer than the historical averages.

Nitin Kumar: Great. Thanks for the detail there. You know, Shane, speaking of the deck, I noticed slide 19, you talk a little bit about your power and midstream interest. Some of your peers and partners have talked about power generation and supplying power for data centers out of the Permian. You have some capacity. Is this an area where you are looking at opportunities and maybe give us a lay of the land in terms of, you know, risk and opportunities there that you’re seeing?

Blake Sirgo: Yeah. Nitin, this is Blake. I’ll take that one. Short answer is yes. We’re very much engaged in those discussions. The Waha gas molecule is very advantageous for power generation, and so it has brought in a lot of parties that are interested not just generating base load power, but also data center loads. And so we’re in discussions with all those, everything from good old-fashioned combined cycle plants to behind-the-meter type power solutions for data centers. It’s not the clearest landscape to understand. There I think everyone’s still trying to figure out exactly what the end state looks like. But we have so many molecules in so many places that we’re really well-positioned to take advantage of some of this. And I’m hopeful we’ll have some good announcements coming before too long on this.

Nitin Kumar: Great. We’re looking forward to those. Thanks, guys.

Operator: Your next question comes from Neal Dingmann from Truist Securities. Your line is now open.

Neal Dingmann: Good morning. Thanks for the time. Guys, my first question just on the continued operational efficiency improvement. Blake, in the slide, you clearly are demonstrating the upside you’re seeing here. I’m just wondering maybe for Blake. Just, you know, like, are you seeing this maybe talk about potential further opportunities both in the Permian and, you know, are you expecting the same sort of upside in the Marcellus as well?

Blake Sirgo: Yeah. Sure, Neal. Happy to talk about efficiencies anytime. When I look back on 2024, the three areas that we really focus on in drilling, drill feet per day, you know, these huge projects, road drilling, but even outside of our roads in Culberson County, our well counts on our projects are so large now. Our rigs just stay camped out. We minimize modes, and we hit a record drilling feet per day across our whole fleet in 2024. On the frac side, our frac efficiencies are up dramatically year over year. And that’s due to some strategies that we’ve been working with our frac partners on that really focus on maximizing all the available horsepower and minimizing transition times. We have transition times now that are averaging close to 20 minutes between stages, which is pretty unheard of from a few years ago.

And then lastly, you know, we’re always really focused on well trouble. It’s not a matter of if, it’s a matter of when. We poke a lot of holes in the ground and things go wrong sometimes. But we have a really rigorous program to deal with well trouble and to get out of it as quickly and cost-effectively as we can. And so those three things are always at play. Will continue to be at play throughout 2025. Something new we’re spending a lot of time and energy on, not necessarily new, but I think it’s gaining more traction. It’s just our focus on frac design, particularly on these Bone Spring sands and shallower zones across New Mexico. That we’re prosecuting. With the help of our ML models, really rightsizing our fracs. You’re seeing maybe in some cases, we can get the same productivity at a lower cost.

Some of that made up, you saw in our synergies on the new assets. And that’s just a really exciting frontier for us. And we’re gonna keep pushing frac design hard.

Neal Dingmann: Great details. And then just a second on maybe the upcoming return of your Marcellus activity. I’m specifically wondering will the focus continue to be primarily on Lower Marcellus? Will you be able to co-develop several of the areas focused on both the lower and the upper?

Michael DeShazer: Yes, Neal. It’s Michael here. Yeah. We will be returning to the box in 2025 and overfilling with some Upper Marcellus wells, but co-development is also in the plans for the box as we move forward as well. So that we will see increasing amounts of Upper Marcellus as a part of our program. And I don’t think it’s a surprise to anyone that that’s a little lower in terms of productivity than the lower Marcellus. But I think the context is important, and the lower Marcellus is some of the best shale rock in the lower 48. So you will see our program move more to the upper over time, but with lateral links, improving our capital efficiency, will allow us still to hold our production flat at that 2 BCF number that we’ve talked about. And I think that’s better than a lot of the other gas shale plays that are out there.

Tom Jorden: You know, I also wanna add, getting that cost structure down is huge for the Marcellus. Really a testament to that team. It’s part of why we like to be multibasin because every now and then, you wanna send teams back to the drawing board and have other places take your capital. And they went back to the drawing board and they came up with some incredible innovations. We mentioned along laterals, well-designed water handling. I mean, our that cost really makes both the lower and upper much much more attractive to us than they’ve been, you know, four or eighteen months ago.

Neal Dingmann: For the ad. Thanks, Gil.

Operator: Your next question comes from David Deckelbaum from TD Cohen. Your line is now open.

David Deckelbaum: Morning, Tom, Shane, everyone. Thanks for taking my questions. Tom, I was just curious if you talk about the Marcellus program a little bit more, you know, for 2025. The lateral lengths are obviously significantly longer this year, excuse me, especially in the upper Marcellus. You know, should we think about that as the go-forward plan in future years and I guess, how did you guys sort of approach that development plan, you know, versus, you know, perhaps, like, cannibalize or weighing that as, you know, cannibalization of inventory, or is this just a this is just the most optimum kind of PV over I?

Tom Jorden: Look. That’s a great question. Cannibalization of inventory is that I just reject that premise. The inventory is best exploited the most capital-efficient way. So we don’t count sticks, and we don’t give ourselves medals for the number of sticks. Back if you can reduce the number of wells you drill and generate higher returns, spending lower and generate the same volumes, that’s the right way to prosecute your inventory. And we’ve seen that, you know, I know your question is on the Marcellus, but you’ve seen us talk about that in the Permian where we have examples where we’re drilling fewer wells and offset operators and yet cumulative production is equal to our neighbors. So, you know, we’re very much we love the long laterals.

It’s also really good for that environment. This is not the Permian Basin. This is very pristine rolling hills. There’s a lot of farms and, you know, dairy operations going on there. We really try to minimize our impact on the community. And these lower longer laterals let us build fewer pads, less capital on hookups. It’s just a win-win in every direction you look. We’re gonna continue to try to find that everywhere we can.

David Deckelbaum: I appreciate that. And I guess I just wanted to clarify just the remarks is just as a lot of this Marcellus activity, you know, appears to be more back half-weighted, I guess, how much of that sort of overall budget should we think of as being kinda contingent on continued strength in the gas curve?

Tom Jorden: Well, we said in our opening remarks, the midpoint is not contingent. The midpoint says, you know what? We’re probably gonna lay some activity down midyear, but if we were to continue as a pace, they would add about $50 million to our capital program. And look, you know, when we get there and make that decision, I think it’ll be obvious because we’re all gonna be watching strength in gas markets. It’s just, you know, there have been times when that strengthening gas market’s been a mirage. And we have the ability to not commit and that’s kind of we’re gonna take that luxury to the very last day.

David Deckelbaum: Appreciate the color, John.

Operator: Your next question comes from Derrick Whitfield from Texas Capital. Your line is now open.

Derrick Whitfield: Good morning, and thanks for taking my questions. I wanted to focus on the gas market with my first question. Regarding the three-year outlook, there’s clearly a lot of optionality built into your growth outlook. And while you’re returning activity to the Marcellus and highlight the potential to further add activity, it would seem the macro environment we’re seeing now is perhaps the most constructive one. We’ve seen them all over a decade. With the understanding that there’s capital tension between the Permian and gas assets, would you expect both the Anadarko and Marcellus to return to growth over the next three years if the gas market plays out as the strip indicates?

Tom Jorden: Lord, I hope so. I mean, that’s what that’s why we have these assets. And, you know, it’s just fascinating to see the components of our cash flow, ebb and flow with the commodity markets. But one consistency is our overall cash flow and our ability to maintain consistent programs across our platform. And I’m gonna let Blake comment on this, but, you know, we just we love the competition between different parts of our portfolio. We love the tough decisions it puts upon us, and we love the way our teams fight for capital by trying to become more and more efficient.

Blake Sirgo: Yeah. I mean, I just echo Tom. That would be a great problem to have if we had record gas prices to drive these basins. But I always think it’s important to reiterate. We’re not targeting growth or targeting returns. That’s what underlies our capital allocation program. If we saw, you know, sustained gas prices which elevated those returns, naturally capital would flow there and the result might be gas growth, but it is a very dynamic gas market that we’re a part of now. Don’t just worry about winter anymore. We watch LNG flows every day. We watch trains. We watch the power demand story very closely. And now we’re watching international pricing because they can move Henry Hub. So the much more dynamic market than it used to be and we position ourselves to be ready to take advantage of it and when it plays out.

I think it’s also important to add that the price ratios matter as well. You know, it’s not just the gas price itself, but we’re allocating correct capital across all three business units. And so we’re watching close how those economics change in terms of Permian or Marcellus and Anadarko allocations based on the relative oil and gas stream. So that’s an important component to also think about.

Derrick Whitfield: Makes sense. And going back to slide 19 for my follow-up, there’s been a lot of discussion on downstream partnerships to support the build-out of data centers. And as you guys have highlighted, could you perhaps speak to where those conversations are for you and what basins and what role you’d like to play in that arena more broadly?

Blake Sirgo: Yeah. You know, I’d say the Permian is probably the one we’re spending the most time on, although we have inbounds in the Anadarko and Marcellus as well. It’s really that Waha gas molecule that seems to be attracting a lot of the power providers. But, you know, like I mentioned earlier, commercially, this is still very uncharted waters. Trying to find long-term commercial deals and anchor gas supplies is a difficult task. So I still see a lot of room for negotiation in this basin. We’ll see how it plays out.

Tom Jorden: Yeah. I might remind the listener, we already have a fair amount of power pricing in our Marcellus gas portfolio. And we are working on bolstering that. We’d like to see a little more power pricing in our natural gas delivery.

Derrick Whitfield: Absolutely. Thanks. Great update, guys.

Operator: Your next question comes from Josh Silverstein from UBS Financial. Your line is now open.

Josh Silverstein: Yes. Thanks, guys. Just sticking on the gas theme, if you did want to ramp gas volumes further, could you do it in the Marcellus, or is that tapped out from a capacity standpoint and you’d have to start adding CapEx to the Anadarko?

Blake Sirgo: I mean, as far as takeaway, no. It’s not capped out. We’re down quite a bit from our all-time highs. And so is Northeast PA. In general, volumes are down. So there’s room in those pipes to grow. Generally, the more volumes we stack on, we’re getting into a little more expensive feet. But that has to be accounted for in our drilling decisions. You know, that’s all taken into our incremental decisions. So, but yes, we could grow volumes.

Josh Silverstein: Got it. And then Shane mentioned the $1 billion debt reduction for this year. Is the buyback on hold until that’s complete or will you do some buybacks during this process as well and then ramp the buyback after the $1 billion is achieved? Thanks.

Shane Young: Yeah. Thanks, Josh. No. The buyback’s not on hold. But we’re going to prioritize debt repayment. So, you know, if you think about it, over the course of the year and we sort of laid out some illustrative free cash flow scenarios in a few of the pages there. You know, and some of which sort of leave room for both buybacks and term loan repayment like the current environment that we were in. But even in that case, you know, I would expect to see that the buyback more back-end loaded and the term loan paid out more front-end loaded just as we go through the year. But not necessarily at the it’s not turned off. I will tell you that. We would certainly look to be opportunistic and we’d still have a buyback program. So it’s not turned off while we’re paying down our term loans.

Josh Silverstein: Okay. Thanks, guys.

Operator: Next question comes from Scott Gruber from Citigroup. Your line is now open.

Scott Gruber: Yes. Good morning. I want to come back to the growth capital allocation just given the macro backdrop. So if gas does stay constructive, let’s say it’s $4 along the curve and oil’s kinda flattish at $70. How would you allocate gross dollars between the Marcellus and then Anadarko in that environment?

Tom Jorden: Well, it’s not complicated. It’s absolutely gonna be on return on investment and what we think generates the best financial outcome. So it’s always a horse trade. You know, we have outstanding gas assets in Anadarko, and those assets also have natural gas liquids. So depending on where that pricing falls, returns can be competitive. So it’s all about competition and, you know, with current gas prices, current forecast, and current outlook, our Marcellus dry gas is competing nicely.

Scott Gruber: Got it. Got it. And then turning to development costs, I’m looking across your Delaware position, Culberson obviously leads the pack with the road developments and all the infrastructure you have in place there with your partner. But as we kinda become a bigger percentage of your activity set, can you talk about the path to close the cost gap? Yeah. You think about that three-year plan, can we see that cost gap closed materially?

Blake Sirgo: I sure hope we continue to see it closed materially. That’s what our teams are hard at work at. As we’ve talked about before, Culberson’s pretty unique. We own and operate four consecutive townships and all the infrastructure inside of it, so it gives us tremendous flexibility in how we build capital-efficient programs. But we think we’ve created the bones of that with these new assets. We built a large block. There are some existing, you know, marketing contracts and things that we’re working through now to try to optimize long-term. But there are some midstream assets that we now own and control that we’re looking at very closely also. Power’s a big story in that part of the world. We’re looking very closely at power.

What kind of power we’re gonna need over the next several years and how we might be able to get a jump on that and expand it. So, yes, have no delusions. Our goal is to use our same economies of scale in Lee County that we’ve used in Culberson over the years.

Scott Gruber: I appreciate the color. Thank you.

Operator: Your next question comes from Kalei Akamine from Bank of America. Your line is now open.

Kalei Akamine: Hey. Good morning, guys. Tom, Shane, Blake. For my first question, can you talk about your unit OpEx guide? It seems to be moving up meaningfully year over year. I just wanna understand what’s driving that. Is that the new Permian assets? And if so, do you see a pathway here to grind it down?

Blake Sirgo: Yeah. Sure. This is Blake. Happy to take that. Yes. A lot of it is the new assets. So the new assets are very oily. Low GOR, so higher per unit cost on LOE. But also fantastic margins. So that’s impacting our overall unit cost. And then now just the way the mix works at Coterra with these new assets, more BOEs from oil, compared to our BOEs from gas in Marcellus and Anadarko. It’s tilting that per unit cost.

Kalei Akamine: Got it. That makes sense. Like, on your oil guide, 2025, 152 to 168. The high end appears to imply Permian oil jumping significantly in the second half of this year. I know your thoughts on where Permian oil can exit the year.

Blake Sirgo: No. Not really gonna quote an exit rate for 2025, but we, you know, setting up to the right consistent growth is what these programs generate. Steady activity is really what’s running all year long.

Kalei Akamine: Okay. Thank you.

Operator: Your next question comes from Matt Portillo from DPH. Your line is now open.

Matt Portillo: Good morning, all. Just circling back around on the gas asset. Tom, I think two quarters ago, you talked about the upper Marcellus threshold from a return perspective, meeting kind of a mid-three hurdle to allocate capital to the asset. Obviously, strips well above that today, but was just curious from a longer-term perspective with the increased lateral length and the lower well cost that you guys have been able to achieve, where do you think that new threshold is for the Upper Marcellus specifically?

Tom Jorden: Yeah, Matt. I think I would still quote mid-threes. You know, we’re watching those gas markets carefully. We really like some of the fours that creep up into that price file. But, you know, it’s as I’ve talked in the past, it’s not just about our projected at current prices. It’s also about what could happen if that price would fall. And how much resiliency do you have in your program? You know, we were looking at our Permian program recently, and we can take that received price in the Permian. And if it were to fall to $40 oil and stay there forever, our 2024 program fully burdened with all overhead still generates a return well in excess of our cost of capital. And so that’s our we like that. That’s resilient. That means you can make investments, and you can have a high degree of confidence that the cycles and price file will not turn those investments south on you.

And so it’s not just pricing in the gas markets. It’s resiliency. And that’s why we’re looking at increasing demand, looking at increasing LNG exports. We’re looking at what’s happening not only domestically, but globally. We’re looking at our new energy team in Washington and some of the changes that they’re bringing to the fore. And we are very optimistic about a structural reset that increases the resiliency of gas investments.

Matt Portillo: Great. And then just as a follow-up for the Marcellus from one of the prior questions, with the two rigs that you guys have running starting in April, if you were to hold those in place, is there any color you might be able to provide in terms of how many wells you could drill for the remainder of this year and then any incremental color you might be able to provide on the split between the upper and lower Marcellus program for that drilling program this year?

Tom Jorden: Yeah, Matt. We’re just not prepared to provide that kind of guidance about around a future pivot point and not to, you know, don’t mean to dodge that. It’s just we have about five pivot points we’ve modeled, and it’s just more detailed than I think would be productive.

Matt Portillo: Understood. Thanks.

Operator: We will be moving on. Our next question comes from John Abbott from Wolfe Research. Your line is now open.

John Abbott: Good morning, and thank you for taking our questions. I’m on for Doug Leggett. You know, maybe just a couple quick ones here. You know, you just did the acquisitions. Any thought on the impact on future cash taxes at this point in time? Maybe that goes to you there, Shane.

Shane Young: Yeah. No. I appreciate that. So yeah. You look a couple of things I’d say. One, from a tax perspective, we’re still in the middle of booking our allocations. So this will be refined over time. And I think as we, you know, get into the first quarter, you know, we’ll probably have something a little better. I would tell you, you know, I would guide for an effective tax rate perspective in the 20% to 25% area. We’re hoping to sort of be in the middle of that range. And then I think we will see some improvement from bringing over all of that basis into our tax base. Exotera. And, again, we’re trying to refine our view on exactly what that impact will be. I would say of that effective tax rate, a good working assumption for the moment would be 90% to 100% cash basis. Which is a little bit of an improvement from where we were in 2024. But that would probably be a good rate to model going forward.

John Abbott: Appreciate it. And just quickly for the second question here, I mean, continue to see strong efficiencies here. Given that you’ve given us your updated three-year guide, you sort of look at the Permian asset, you know, if we get you have about 15 years of inventory. The inventory front is always better than the back. At what point do you think looking out into the future, that you could see a potential change in capital intensity at this point given the efficiencies that you could achieve?

Blake Sirgo: Yeah. John, this is Blake. You know, I would say with what’s interesting is this inventory we’re doing today didn’t look as good as it is a few years ago. We are constantly improving our near-term inventory through all the different capital-efficient things we’ve talked about. And so don’t really view it as some stark inflection point in the future. You will see us migrate to different zones besides just the Wolfcamp A throughout time, but I’m continually impressed at how our teams find ways to really generate capital efficiencies from these other zones and I would expect that to continue.

John Abbott: Appreciate it. Thank you very much for fitting us in.

Operator: Your next question comes from Leo Mariani from ROTH MKM. Your line is now open.

Leo Mariani: Yeah. Hi. I wanted to continue to focus a little bit here on the Marcellus. I think you made some comments in your prepared remarks here that you guys were able to drill Dimock, you know, again for the first time in a while. I know that’s been kind of opened up a bit there. I was hoping you could, you know, basically help us out by kinda quantifying, you know, roughly kinda how much runway is there in Dimock. I don’t know if you wanna that is in terms of wells or years to drill with, you know, say a one rig program or something.

Michael DeShazer: Yeah. This is Michael. Like I said earlier, we will be going back into the Dimock box in 2025 and drilling some overfill wells on top of our existing lower. So there’ll be some Upper Marcellus wells that we drilled, and we’re excited to see those wells come on. And then moving into 2026 and the out years, there is a the north side of the box is still not developed fully. So we’ll be able to come back in with new longer laterals and fewer wellbores than we anticipated at our original plan, and that’s some of the cost efficiency and dollar per foot savings that we’ve been talking about. Is the team during this period where there wasn’t as much activity really spent a lot of time trying to optimize the developments in the box and make sure that we were able to make them as capitally efficient as possible.

And they were able to reduce the capital cost in that development by over $50 million. So, yeah, you’re gonna see continued activity from us in the coming years in the box.

Leo Mariani: Okay. And then just to follow-up here on the gas side, just wanted to get a high-level sense. I know you guys said that you’re obviously gonna approach this with a little bit of caution. There’s been head fakes on gas over the years, but you’re kind of at today’s prices, call it, you know, $4 Henry Hub and $70 WTI. How do the returns compare in your kind of traditional Permian program versus the lower Marcellus today?

Tom Jorden: They’re very comparable. And if we had certainly assurance of that, we’d probably pull that lever, but they’re quite comparable in the range you talked about.

Leo Mariani: Thank you.

Operator: Next question comes from Paul Cheng from Scotiabank. Your line is still down in Miami. Thank you. I have to apologize. I’m in the so there’s a little bit noisy in the background. For the Coleman Gray in Marcellus. Even if the economic yes. Good. Given the resource and you’re saying that you have about twelve years, what should we assume is the maximum? How much? Or that the production that you could expect?

Tom Jorden: You know, I just we don’t manage our company by production. I think we, you know, we manage by returns. And this is, you know, one of the things that we’re looking at right now is what is our market for that gas. We’re trying to find new markets, trying to bolster our weighted average sales price. But, you know, I don’t think you’d see us return to the growth trajectory that we had a decade ago. But, you know, very slow and steady single-digit growth is certainly something that might be an outcome. I’d say that. But, look, even maintenance capital at 2 BCF level would be just fine with the right weighted average sales price.

Paul Cheng: Great. And also that, can you give us some idea that on by quarter, how’s the well coming on stream and also the CapEx is going to try and look like? Are they going to be variable? I know that you must sell it. You’re going to start two way in, by eight o. But should we assume that subsequently, that is just going to be variable and also a bug in the permit? Thank you.

Blake Sirgo: Yeah. This is Blake. You know, I’m not really gonna give, like, quarter-to-quarter guidance. I would just say, you know, due to the plan and then Marcellus, you’ll see those two rigs start. Naturally, there’s a little lumpiness with getting back to work. We’re just bringing frac activity back. But in the Permian, it’s really driven by our frac crews. We run three steady crews. And that tends to even out all our gross there.

Shane Young: Yeah. I’m on the page for 36 can at least visually give you an idea of sort of what the year looks like from an activity standpoint. You know, which should correlate a little bit towards capital over time.

Paul Cheng: Okay. We do. Thank you.

Operator: Thank you. I’d now like to hand the call over back to Tom Jorden for final remarks.

Tom Jorden: Well, thank you, everybody. We appreciate your questions. And we look forward to delivering on all of our plans for 2025 and the out years. Thank you very much.

Operator: Thank you for attending today’s conference call. You may now disconnect.