Coterra Energy Inc. (NYSE:CTRA) Q2 2025 Earnings Call Transcript

Coterra Energy Inc. (NYSE:CTRA) Q2 2025 Earnings Call Transcript August 5, 2025

Operator: Thank you for standing by. My name is John, and I will be your conference operator today. At this time, I would like to welcome everyone to the Coterra Energy Second 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. Please go ahead.

Daniel Dennis Guffey: Thank you, John. Good morning, and thank you for joining Coterra Energy’s Second 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; Blake Sirgo, Executive Vice President of Operations. Michael Deshazer, Executive 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.

Thomas E. Jorden: Thank you, Dan, and thank you, all of you for joining us on the call this morning. I will provide an overview before handing it over to Shane for financial results and an operational update from Blake. Coterra had an excellent second quarter. We exceeded the high end of our guidance range for natural gas and total barrel of oil equivalent production and came in well above our midpoint on oil volumes. Our revenues for the quarter were nicely balanced between oil and natural gas, inclusive of natural gas liquids. We generated outstanding returns on capital and are on track to finish the year investing approximately 50% of our cash flow. A low reinvestment rate is one of the primary measures of asset quality, and Coterra remains top tier in our ability to deliver consistent profitable growth with high capital efficiency.

I would like to provide an update on our Culberson Harkey program. We are on track with our efforts to address the issues that cropped up in our Windham Harkey flowbacks last quarter. We have additional evidence that strongly indicates that the issues we encountered are localized around the Windham development and not widespread through our Culberson assets. Blake will give you more details around 6 new Harkey wells recently brought online that are in the immediate vicinity of the Windham Row. We’re making meaningful progress and expect the Harkey to be a solid contributor to our program for years to come. We have seen some weakening in natural gas prices over the past quarter and the recent announcement of the cessation of the OPEC + curtailments have led to a softening of oil markets.

We live in an environment of perpetual commodity uncertainty. Coterra’s assets and capital allocation discipline allow us to maintain a steady operational cadence across modest peaks and valleys. Last quarter, during the uncertainty around the impact of tariffs, the [ Iranian enrichment ] response, the broader Middle East conflicts and the potential impact of these and other forces on the world economic outlook, we discussed the plan to lay down activity. As we’ve seen this macro situation stabilize, we have decided to keep 9 rigs deployed in the Permian, 2 rigs in the Marcellus and 1 to 2 rigs in the Anadarko. These decisions in aggregate will maintain consistent activity through the second half of 2025 and put us on solid footing for 2026.

We look forward to updating our 3-year outlook in February. As always, our outlook will be underwritten by steady cash flow, outstanding assets and investment returns that help to accomplish our mission of consistent profitable growth. We seek to grow our free cash flow and demonstrate its durability. We see the quality and durability of our free cash flow as one of Coterra’s differentiating features. Volume growth is an output, not an input. We are bullish on the long-term prospects for our industry and for Coterra in particular. Recently, there has been discussion about the industry being in the final chapter of Tier 1 inventory. To that, we would like to make 2 comments. First, although it is inevitable, it will happen to different companies at different times.

With our deep inventory of low- cost assets, Coterra is best positioned to maintain its strong capital efficiency for many years to come. Second, a decline in Tier 1 inventory will ultimately lead to an increase in cost structure and an increase in the clearing price for incremental volumes. A logical consequence will be commodity price increases necessary for our industry to keep pace with demand. These consequences will materialize differently for oil than for natural gas, furthering our thesis of having meaningful exposure to both commodities. And one final thought. Our industry will indeed face headwinds. But if we have learned one lesson in the past 20 years, it is to never underestimate the ingenuity, adaptability and creativity of the American oil and gas producer.

Our industry will find a way forward and Coterra will be there to help. With that, I will turn the call over to Shane.

Shannon E. Young: Thank you, Tom, and thank you, everyone, for joining us on this morning’s call. Today, I’d like to cover 3 topics. First, I’ll quickly summarize the important takeaways from our second quarter financial results. Then I’ll provide an update on our guidance, including the third quarter as well as the full year 2025. Finally, I’ll provide an update on our balance sheet and our cash flow priorities for the remainder of the year. Turning to our strong performance during the quarter. During the second quarter, Coterra’s oil production came in 2% above the midpoint of our guidance, while natural gas was above the high end of the guidance range due to outperformance in all 3 business units. BOEs were also above the high end of the guidance range with strong NGL volumes as we were in ethane recovery for most of the quarter.

The Permian had 49 net turn-in lines during the quarter, and the Anadarko and Marcellus had net turn-in lines of 9 and 3, respectively. We expect TILs for the year in all areas to continue to be in line with our annual guidance. Pre-hedge oil and gas revenues came in at $1.7 billion, with 52% of revenues coming from oil production. This is a 7% increase in oil contribution quarter-over-quarter, driven by higher oil volumes and is consistent with our balanced commodity strategy. Cash operating costs totaled $9.34 per BOE, down 6% quarter-over-quarter on higher volumes and in line with our annual guidance midpoint. We reported net income of $511 million or $0.67 per share and adjusted net income of $367 million or $0.48 per share for the quarter.

Capital expenditures in the second quarter were $44 million less or 7% below the midpoint and slightly below the low end of our guidance range. This was driven primarily by timing and, to a lesser extent, additional cost savings relative to expectations. Discretionary cash flow for the quarter was $949 million, and free cash flow was $329 million after cash capital expenditures. Looking ahead to the third quarter and full year 2025. During the third quarter of 2025, we expect total production to average between 740 and 790 MBoe per day. Oil is expected to be between 158 and 168 MBoe per day, and natural gas is expected to be between 2.75 and 2.9 Bcf per day. We expect capital for the quarter to be $650 million at the midpoint of guidance, and we anticipate that this will be the high quarter for capital for the year.

This quarter-on-quarter increase is driven largely by an increase in the Anadarko, where we plan to continuously run a frac crew during the quarter. For the full year 2025, we are increasing annual MBoe per day production guidance midpoint by 4% from 740 to 768. We are maintaining the oil guidance midpoint while tightening the guidance range slightly. Importantly, we’re increasing our natural gas volume guidance midpoint 5% from 2.78 to 2.9 Bcf per day. As previously indicated, we expect full year capital to be about $2.3 billion or a reinvestment rate of around 50% of 2025 cash flow. This level of spend maintains consistent activity in all 3 business units during the second half of 2025, which we believe gives us good momentum going into 2026.

As a result of recent U.S. tax law changes, we now expect our current tax percentage of total tax expense for the full year of 2025 to be between 40% and 60%. As a result, we expect minimal current taxes in the second half of the year. Looking forward, we would expect the current percentage to move closer to 70% to 90% of total tax expense. With regard to our 3-year outlook provided in February, we remain highly confident. This outlook is underpinned with a low reinvestment rate, improving capital efficiency, and we believe delivers attractive value with modest production growth. Turning to shareholder returns on the balance sheet. Yesterday, we announced a $0.22 per share dividend for the quarter. It was one of the highest yielding base dividends in the industry at over 3.5%, and we remain committed to reviewing increases to the base dividend on an annual basis.

During the second quarter, we repaid an additional $100 million of our outstanding term loans that were used as part of the financing of our acquisitions earlier this year. This brings our total term loan pay down to $350 million in the first half of 2025. In addition, we returned $191 million directly to shareholders through our base dividend and share repurchases or 58% of our free cash flow. We ended the quarter with an undrawn $2 billion credit facility and total liquidity, including cash of $2.2 billion. We expect to continue prioritizing deleveraging. And in the current environment, we expect to fully repay the remaining $650 million of term loans during 2025. We are quickly executing on getting our leverage back to home to around 0.5x net debt to EBITDA.

At the same time, as previously indicated, we expect our share repurchase activity to be weighted towards the back half of the year particularly in light of current share price. 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 protecting our shareholder return goals. In summary, Coterra’s team delivered another quarter of high-quality results, both operationally and financially across all 3 business units. For 2025, we continue to expect consistent oil production growth throughout the year, substantial free cash flow generation at over $2 billion and rapid deleveraging. With that, I’ll hand the call over to Blake to provide additional color and detail on our operations.

Blake?

Blake A. Sirgo: Thanks, Shane. On the activity front, we are focused on consistency which, in turn, helps optimize our dollar per foot cost and project economics. We expect to maintain 9 rigs in the Permian in the second half of the year, which is 1 rig less than we originally guided to in February. Our current plan allows us to consistently run 3 frac crews in the Permian, including our Culberson simul-frac fleet for the remainder of ’25 and into ’26. In the Marcellus, we have elected to take our second on-ramp and keep 2 rigs running throughout the year. This activity pushes Marcellus capital up $100 million from our original guidance. In aggregate, we expect full year capital to be approximately $2.3 billion. Our consistent activity in the second half of ’25 positions Coterra for a highly capital-efficient 2026.

With the first half of 2025 behind us, we are realizing some wins in the field that are beginning to impact our costs. In the Permian, we are currently projecting an all-in cost of $940 per foot, which is down 2% from the first of the year and down 12% year-over-year. These cost reductions are driven by a continued focus on drilling and completion efficiencies as well as some reductions in our market rates for the second half of the year. We are seeing an increase in rig and frac availability, which is leading to competitive pricing in our bids. Our 2025 program is delivering the strong capital efficiency that we have come to expect from our Permian assets. Integration of the Franklin and Avant assets is complete and results continue to beat expectations as we continue to lower our cost structure and delineate new landing zones across the Northern Delaware.

We remain on track to hit our annual oil guide. Turning to Culberson County. The Wolfcamp wells at Windham Row continue to exceed expectations with a projected PVI 10 north of 2.3 at strip pricing and an all-in cost of $894 per foot, an exceptional outcome across the road. Remediation efforts on the Windham Harkey wells are almost complete. We’re seeing improved pressure drawdown, declining water cuts and a modest oil response. However, in aggregate, the remediated wells are not yet contributing material incremental oil volumes. As such, we do not expect Windham Harkey to impact our current full year 2025 oil guidance. The water introduced from the shallow disposal zone will take time to recover. And although we expect to see gradual oil recovery over time, we may not fully achieve our original predrill volumes.

Importantly, during the quarter, we brought 6 new Harkey wells online in Culberson County that were immediately adjacent to Windham Row. These wells are in flight while we were bringing on Windham Row Harkey wells, and we are able to adjust the wellbore designs to ensure mechanical isolation. These wells have come on strong and are meeting or exceeding expectations. This gives us confidence that the mechanical issues we encountered on Windham Row were localized and have been addressed. Across the basin, our broader Harkey program continues to perform well. The success of this 6 new wells in Culberson County reinforces our confidence in the long term potential of the Harkey interval across the asset. Outside Culberson, we drilled 21 gross Harkey wells in 2024 and plan to drill 10 to 20 gross wells annually from 2025 to 2027, driven by consistently strong returns.

We continue to view Harkey as a valuable target across the basin for Coterra and other Delaware Basin operators. Results in the Marcellus continue to be strong. As Shane noted, we significantly beat our natural gas forecast during the quarter. A large component of this beat was the outperformance in our Marcellus production, with significant contribution from the box wells that came on last winter. The 11 wells we turned online in the box in December 2024 have been the most productive wells in our Marcellus history, with a peak 30-day rate of 450 million cubic feet per day across the 11 wells. Coterra is back to consistent work in the Marcellus with 2 rigs drilling and 1 frac crew. We plan to bring on 7 to 12 more TILs between now and the end of the year with more completions in early 2026, giving us a nice ramp throughout winter.

Our focus in the Marcellus continues to be improving capital efficiency through cost reductions and extended laterals. We currently expect an average lateral length of 17,000 feet across the program, which is helping to drive our go-forward cost structure of $800 per foot. Our Anadarko program continues to bring in strong results with the [ Roberts pad ] coming online in Q2 with stellar results. This 9-well project achieved a 30-day equivalent IP of 173 million cubic feet per day. This productivity paired with strong NGL yields makes us one of the best gas projects in our portfolio. We continue to gain efficiencies in our Anadarko program with our first 3-mile project coming online later this year, with an impressive all-in cost of $923 per foot.

Our Anadarko team is laser-focused on driving capital efficiency and extending our laterals across the asset. Lastly, an update on our gas marketing portfolio. We are excited to announce our new power netback deal in the Permian with a 50,000 MMBtu per day long-term sale to Competitive Power Ventures new Basin Ranch power plant in Ward County, Texas. This deal is the culmination of a multiyear collaboration between Coterra’s marketing team and CPV to deliver a differentiated in-basin project that not only delivers a firm fuel supply to CPV’s new facility, but also adds additional power netback exposure to Coterra’s gas sales portfolio. Similar to our recent LNG transactions, Coterra continues to execute on our strategy of pursuing differentiated gas sales across all of our 3 basins.

We are not interested in making additional investments and commitments in markets that we already have ready access to. We will continue to focus our execution on sales that bring diversity and price enhancement to our portfolio. And with that, I’ll turn it back to the operator for Q&A.

Q&A Session

Operator: [Operator Instructions] Your first question comes from the line of Neil Mehta with Goldman Sachs.

Neil Singhvi Mehta: I just want to start off on Harkey just round out this point. It sounds like you feel like you’ve gotten through it. So can you just give us a level set of how much conviction you have that you work through this issue, the timeline? And when do you see production really being at optimal level?

Thomas E. Jorden: Yes, Neil, thank you for that question. As Blake said, remediation efforts look like they’re highly successful, both shutting off water flow on existing wells, but also we did change our wellbore design. And I think that’s really the key point here. These wells are in immediate vicinity, would have been exposed to the same phenomena and they’re flowing back pretty as pink. And so that’s exactly what we hope for. As Blake said, go forward, it’s going to take — we put a lot of water in this formation, and it’s going to take a while to dewater this. So we’re being very conservative in our go-forward oil forecast from Windham Row. But we are full steam ahead on Harkey and really do look forward to getting this problem behind us.

Neil Singhvi Mehta: Yes. And then just the $100 million of activity that you add to the Marcellus and the rig add. Can you talk about that there’s been a big debate in the investment community about whether we’re overproducing with some of these scrapes kind of around 108 Bs right now, which is probably 1 to 2 Bs higher than most of us thought we would be. Does this feel like the optimal time to be leaning into the gas program? And how do you think about the risk of if the leaders are adding supply before the demand and inventory signals are there?

Thomas E. Jorden: Well, we do see growing demand with LNG exports. Of course, this whole power story is going to be ramping up. If we could pick optimum timing, we’d be — so we stand alone in our industry if we could do that. I can tell you that when we look at our forecast of current pricing, our Marcellus program is our best returns right now. And that’s because of the quality of these wells and the costs that we’re bringing the supply on. Blake, do you want to comment on that?

Blake A. Sirgo: Yes. I’ll just say that taking the market is a very difficult thing to do with the Giant D&C machine. And so we’re pretty focused on consistent activity. We’ve really lowered our cost structure in the Marcellus, which has lowered our breakevens, and that gives us confidence when we go through these modest cycles. And so we feel really good about the projects we have coming online between now and the end of the year.

Shannon E. Young: And Neil, I think it’s important to note that this activity this year comes off zero. I mean we sort of went to zero last year and kind of held that till April and now have picked up. And this level of activity we’re talking about is very akin to kind of a maintenance level for what we’re doing up in the Northeast.

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

Arun Jayaram: I was wondering if you could talk a little bit about the trajectory of your oil growth expectations in the back half of the year? Obviously, you’ve given a third quarter guide. By our math, you’d have to average about 172,000 barrels in the second half to hit the midpoint of your oil guide of [ 160,000 ]. Given Blake’s commentary on consistent activity levels, talk to us about confidence level at the midpoint and how you expect to kind of achieve that fourth quarter run rate which would assume kind of an oil trajectory approaching 180,000 barrels a day.

Thomas E. Jorden: Yes, Arun, high confidence on our part. And I’ll just say, we’ve spent a lot of time on this data, and it’s simple arithmetic. It’s not necessarily a balance of operational things, all of which need to go right. This is simple arithmetic. We have the blessing of having a lot of high working interest projects coming online in the fourth quarter. And that’s just sort of a statistical anomaly. These are projects that we understand. Their names are well known to us. And as we review the on-ramp, some of these are already producing and building as we speak. So we have a high degree of confidence in our forecast. It is simple arithmetic. It does not require operational gymnastics. It’s solid. We’re going to deliver it. Blake, anything you want to add?

Blake A. Sirgo: Yes. I’ll just say the only — the operational cadence is not changing in any of our programs. It’s very consistent. It’s just a matter of really high working interest DSUs coming on relatively close together. And I’ll just mention we are thrilled to have the high working interest in these DSUs.

Shannon E. Young: Yes. And I think since we started guiding for the year, we’ve really tried to point the market towards a bit of a stair step over the course of the year and the trajectory being consistent, not necessarily a flat production over the course of that period.

Arun Jayaram: Fair enough. And my follow-up question is Tom thoughts on — you announced that you believe that you have a new wellbore design, which has fixed maybe some of the issues you experienced in the Harkey in the 1Q conference call. But do you have enough confidence now to codevelop the zones in Culberson County?

Thomas E. Jorden: Well, yes, as we said in our last call, we don’t think this is a co-development issue. So my answer to that is, yes.

Operator: Your next question comes from the line of Doug Leggate with Wolfe Research.

Douglas George Blyth Leggate: Tom, I wonder if I could ask a kind of a high-level question. Forgive me for this, you’re a leader in the industry, and I think your perspective on this could be worth everybody listening to. And it’s really that — the industry often justifies at the individual company level, drilling wells on the basis of wellhead returns, because it’s the right thing for the company, but collectively, the industry ends up the [ slowing price ]. So it’s another way of asking why — I mean you have the option to not spend out $100 million in the Marcellus. Is this a desire to maintain production because the risk, obviously, for the commodity, as it as Neil pointed out, production has been surprising on the upside, and the biggest part of that has been the Marcellus. So I guess I’m asking if you might be part of the problem on the commodity.

Thomas E. Jorden: Well, Doug, the problem with our business is we don’t manage it with a spreadsheet. And so we make decisions sometimes depending on the project, it can be 12 or 18 months in advance. And if we had, had this conversation 6 months ago, I think our conversation would have been very different on gas prices. So I’ll just tell you that Coterra, one of the things that keeps us whole through this challenge, as you lay out, is having a very low cost of supply, and we run our CapEx down to very draconian pricing. So I mean in the case of oil, will run at sub-$50 oil as if that’s the only price that well will ever see through its life. In the case of natural gas, we’ll even go sub-$2. And these investments we’re making are really, really profitable even at that.

Our long-term goal, as I said, is in production. It’s generating free cash flow and demonstrating to the market that we have durability there. And so one of the things that our asset complexion and our mixture gives us the luxury of — is having stable cash flow and the ability to ride through the cycles. And I’m going to make one final point, Doug. We recently did some analysis. We’ve talked a lot about our look back, our look back on our own program. And we go back 20 years and look at every investment we’ve ever made and we tear it apart. And that analysis, we looked at our behavior in the troughs. And because of that lag time, our conclusion is that not only were the investments we made in the troughs, some of our most profitable in our history, but it really told us that a steady cadence of activity is the best way to manage a cyclic commodity business.

So I take your question. I’ll let others describe if we’re part of the problem. But we think our behavior is representative strength of Coterra.

Douglas George Blyth Leggate: I appreciate the answer. And Tom, I was going to go in a different direction, but I’m going to — actually don’t mind, I’m going to ask a follow-up on this because another aspect of having that low cost of supply and a stellar balance sheet, frankly, is that some of your large pure-play gas peers have used that as a crux for managing their tills, almost like seasonally managing their production, shutting in production in the trough, bringing it on into winter and so on. So I guess my question is, is that a consideration for your gas strategy, if not, why not?

Thomas E. Jorden: Blake, why don’t you handle that one?

Blake A. Sirgo: Yes, Doug, I’d say that’s absolutely in our toolkit. We have used that before. It really comes down to our sales portfolio. So we have long-term sales that are anchored to really good deals that are much better than we get in basin. But we do have in-basin cash sales also. And so we really look at that as the incremental molecule. And so you’ve seen us manage production. You’ve seen rolling curtailments and you would see delayed completions and things like that, if necessary. So those are tools we have in our toolkit, but it really has to be done in harmony with the long-term sales portfolio. It’s really important.

Thomas E. Jorden: Yes, Doug, based on our behavior over the last year, I think anybody looking at us would know that we have the wherewithal to shut production in if pricing gets too hostile.

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

Wei Jiang: Shane, I wanted to ask about cash taxes. Thank you for the color you provided earlier. Can you just give us a bit more detail around why the 2025 cash taxes is going down more? And then moving forward, you gave the range of 70% to 90%. How should we be thinking about that range over time?

Shannon E. Young: Yes, Betty, thank you for the question. So look, we are benefiting from 2 primary things. There’s a lot in the bill, but the 2 primary things are: one, a return up to 100% bonus depreciation where we can expense things in the year incurred; and two, the return of some of the R&D expenses that we’re able to do. And really, by nature, those are more timing elements. And so in other words, we’ll get them this year. But over time, those will sort of normalize. And so as we get out over the next 2, 3, 4 years, we will get back to where we are. The other thing I would point out on tax and a little bit of this, particularly when you combine it with the bonus depreciation comment I made earlier is the deals that we did earlier this year all got step-ups in basis.

So it really sort of changed the profile and complexion and sort of our ability to offset some taxable income. But when you combine that with the bonus depreciation element on some of the fixed facilities and assets that we have, it really gives us an advantage in 2025. So again, I would say it’s early days as we sort of get through, we’ll refine our guidance a little bit more, but we knew that would be an important question for this call. So we wanted to be really, really dialed in on ’25 and have a very — a range, but a very educated range on a go-forward basis.

Wei Jiang: So this 80%, can we use that for the next — going forward, that 3, 5 years?

Shannon E. Young: I’d say over the next several years, that’s a good place to be. Over time, again, most of this is a question of timing, whether it’s the R&D expenses or whether it’s bonus depreciation and things will level out again when you get out past 3, 4 years.

Wei Jiang: My follow-up is on the buyback with the incremental free cash flow now the business is generating, should we expect once the term loan is paid off, you will start accelerating on the buyback again? And could we see it going back to that 100% cash return level towards later this year and into next year?

Shannon E. Young: Yes. That’s a really, really fair question. I mean in 2024, we were about 90% of free cash flow in payout. In 2023, we’re probably closer to 76%. So we’ve been at some really elevated levels, we weren’t in debt reduction mode. As we look at the back half of the year, and this is all dependent on sort of the actual conditions. But based on sort of what we see today, we envision being able to pay off the last $650 million of the term loans and at the same time, being able to balance that with some back over the course. Now when we get paid off, so let’s say, we look into 2026, I think you’re spot on that the focus can move back towards buybacks and direct shareholder returns. That being said, towards the end of ’26, we do have a $250 million maturity.

So we’ll have to figure out sort of how that fits into our free cash flow profile in that year, nothing has been decided yet. But yes, absolutely. I think — if you look at the behavior over the last few years and sort of that 75% to 100% range that we’ve been at. I think when we’re out of that debt paydown mode, that’s a place that all other things being equal, you should expect to see more buybacks.

Operator: Your next question comes from the line of Nitin Kumar with Mizuho.

Nitin Kumar: Tom, I want to maybe follow up to Arun’s question. You have a pretty strong ramp-up in oil volumes for the rest of this year. Historically, just given your focus on bigger projects, a big ramp-up has been followed by maybe a little bit weaker or decline but you’re also adding activity or at least retaining activity this year without increasing your guidance. So I’m not asking for guidance for 2026, but how do you see the trajectory sort of beyond fourth quarter? Do you expect a bit more ratable oil volumes in 2026?

Thomas E. Jorden: Yes. thank you for that. Look, fourth quarter is going to be a bit of a flush. We don’t anticipate first quarter being up from fourth quarter. But I’m going to sound like a broken record here. We really don’t worry about quarter-to-quarter as much as we do just the trend upward to the right on an annual basis. So we’re going to have quarter-to-quarter fluctuations because of a lot of things. And we mentioned working interest, which just so happens in the fourth quarter, a lot of the contribution is high working interest. So we’re steady as she goes, a constant level of activity. And — but these kind of quarter-to-quarter fluctuations are just going to be part of the business. But we want to consistently grow, generate growing free cash flow over the duration.

Nitin Kumar: My follow-up is on the gas marketing side, and maybe, Blake, looking at Slide 18, I think 31% or so of your current gas volumes are sold in basin across the 3 operating areas, and you mentioned the LNG contracts and you mentioned — you announced this power deal. So on our math, it’s roughly 8% or 9% of your total corporate gas volumes. Should we expect that these new volumes will be really met by sort of a reallocation of in-basin? And Part B is as you think about the longer-term mix for your gas marketing portfolio, is there an advantage of keeping some molecules priced in basin as well?

Blake A. Sirgo: That’s a good question. And I’ll answer the first part. Yes, I think of these as reallocation of existing sales. We’ve been on a mission for a while now to diversify away from Waha. And that’s why we love this power deal so much. It’s real in-basin demand, but it’s not indexed to the local gas price. We actually get access now to the power strip, and that’s something we really value in our portfolio. So we like those deals. We’re looking at more of those deals all the time, but it has to truly either give us diversity in pricing and then it has to give us enhancement — some sort of enhancement to value over the long run. So that’s really how we look at it.

Operator: Your next question comes from the line of Scott Gruber with Citigroup.

Scott Andrew Gruber: A lot of discussion on the gas strategy. I wanted to come back to the oil strategy, there’s been some comments around preference for operational consistency. If we do see the macro shift again in oil dips back to the high 50s, would the preference be to maintain those 9 rigs in the Permian for that operational consistency. And I assume there’s been some good benefit from lower service costs? Or would you look to pivot back to a lower rig count?

Blake A. Sirgo: Yes. I mean this goes back to what Tom was discussing earlier. We — this is the reason we stress test our projects to very low crude prices, and they’re very resilient in the face of that. And our operational cadence is important to us. As you mentioned, when those things happen, we tend to get lower service cost. And so assuming we’re in a $50 world and not a COVID world, then yes, I would expect some consistent activity.

Thomas E. Jorden: Yes, Scott, let me just add to that. Our business has changed. We still talk about rig numbers, and that’s really not the way we think about it. It’s how many completion crews can we keep running consistently. That completion now is the majority of our capital expenditure. And the biggest disruption we can have is if we have to release completion crews and then bring them back in. So we really think about this in terms of completion crews. We may talk about rigs, but that’s the driver of completion crews.

Shannon E. Young: I think also reinvestment rates is an advantaged part of our story and our strategy. And I think right now, we’re hovering around 50%, and we’ve got some headroom as prices move down to absorb a little bit more reinvestment rate without having to cut capital.

Scott Andrew Gruber: I appreciate that. And then coming back to the Harkey wells, the new well design you made on the incremental Harkey wells on Windham Row, how much of that cost? And you mentioned that the water issue doesn’t appear to be an issue across the broader Culberson County. But are you thinking about applying that well design — the new enhanced well design across Culberson out of an abundance of caution? Or is that not really necessary?

Blake A. Sirgo: Yes, Scott, I’d say, in general, we’re very focused on making sure we always have great mechanical isolation across any disposal zone. And so for these wells we were talking about today, that was a change in cement design, but we’re also looking at casing designs, casing set points, things like that. And then we have to be very specific about where we are in the field and where isolation points are. So we’re very focused on that, but the goal is simple, make sure we have great mechanical isolation no matter where we put a well in the ground.

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

Kaleinoheaokealaula Scott Akamine: This first question is on use of cash. You kind of touched on this in your opening remarks that the term loan is a big near-term priority. The argument for a more aggressive buyback, however, is that your share price is currently at a discount and that you don’t have a balance sheet problem, you’re actually in really good shape. So why not shift priorities and focus more on the buyback?

Shannon E. Young: Well, I’ll hit that one. But listen, we — number one, we’ve been consistent about the priority and what it’s — look, it’s part of our culture is to have a conservative financial profile and credit profile. But I think more importantly, to your question, we see repaying these term loans, getting back to home, as we call it, is really a facilitator for more — one, taking volatility out of the system, which we think benefits our shareholders. And then two, facilitating a return to a more robust and consistent buyback phase sort of along the lines of what we’re discussing with Betty earlier. So we see actually debt paydown is consistent with long-term buyback strategy and getting there as quickly as we can. Now that being said, we’ve talked about having some back-end weighted repurchases in this year if cash flow holds up.

Year-to-date, cash flow has held up. And so that’s good. And to your point, at current prices, that relative attractiveness, it’s not lost on us. So yes, I wouldn’t be surprised if the pace of buybacks picks up relative to what it’s been in the first half of the year.

Kaleinoheaokealaula Scott Akamine: I appreciate that perspective. My second question is on federal lease sales in New Mexico. Following the [ big day ] for bill, I think those lease sales tend to become more frequent. How do you think about using those lease sales to add to your position? Do you see it becoming a more material part of your capital budget going forward?

Thomas E. Jorden: We hope so. There was a day not too many years ago when federal lease sales were a really important part of the calendar. And over the last few years, there’s been a complete absence of them or near complete absence of them. They’re going to be competitive. You’re going to see some headline prices for acreage. Federal leases are highly desirable leases, but we’re going to be in that game, and we’re going to be competitive.

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

David Adam Deckelbaum: Just was curious on just how you’re thinking about the Mid-Con in terms of demand and capital over the next couple of years, particularly just given the movement to more 3 milers this year. How quickly can like a 3-miler program become part of the Mid-Con go forward?

Thomas E. Jorden: I’m going to throw that one to Michael Deshazer, who’s over our business units.

Michael D. Deshazer: Thank you, David. Yes. The 3-mile projects are unique in that, a lot of the development is already in place in [ Hana field ], where we operate in our 3 different areas of Lone Rock, up dip and down dip. So we are going through all of our inventory right now and understanding where can we extend 3-mile laterals because we’ve seen the profitability increase of those in all of our basins. The project that’s scheduled to come on in Q4 was an opportunity where we could easily add on that third mile lateral, and we were excited to do that. But I think it will be a longer-term transition and we will have — because of the way the units have been set up as 2 miles in the past, we won’t be able to move all of that program to 3 miles over time.

David Adam Deckelbaum: Appreciate the color there, Michael. And maybe just Blake, on the remaining Harkey wells or the 22 that are dewatering, do you guys have an anticipated timeline on how long these wells would take to dewater before looking to go back and remediate and return to sales?

Blake A. Sirgo: No. I mean that’s why we really — we covered in the remarks, we mentioned the gradual build over time, and that’s really what we’re expecting. And that’s also why we’re not using it to add to our oil guide this year. We do think it’s just going to be a slow gradual build over time. And so we’ve derisked those volumes this year, and we’ll see how they clean up through time.

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

Derrick Whitfield: Congrats on your update. With my first question, I wanted to lean in on the power gen opportunity for Coterra and the success you’ve experienced in achieving power sales agreements. As this has been an elusive seat for many of your Permian peers, how would you characterize what’s leading to your success and how you’re positioning Coterra as a partner?

Blake A. Sirgo: Yes. Thanks, Derrick. A lot of really hard work is really the only answer to that question. Our marketing team started talks to lots of folks and talks to folks all over the country. But this opportunity is years in the making. We had to find a wonderful partner in CPV who frankly just really understood the market for what it was. There’s — the Permian has a disadvantaged gas price and a strong power demand. It’s a great place to build power plants. But for us, we have to have something differentiated also. We can’t just sell gas at Waha. We already have that opportunity every day. And so those 2 things came together over lots and lots of negotiations, and we were able to find a deal that worked great for both parties. And so those tend to be more the exception than the rule or we would be announcing a lot more of them. But our team knows exactly what we’re looking for, and we’re very diligent. We stay at it.

Thomas E. Jorden: Let me add to that. Our experience, whether it’s power or dealing with some of our LNG purchasers, if you don’t have an investment- grade balance sheet and a good reputation, you don’t get pass the initial conversations. So that’s certainly been an asset for us. And then as far as this power deal, we’re really thrilled to have it from a pricing standpoint. But another element of this that hopefully is not lost is the access to power. In addition to the pricing, we have the ability to purchase additional power and availability of power is a growing concern in the Permian Basin. So it really ticks both those boxes.

Blake A. Sirgo: Yes. I’ll just as a reminder, we have 2 great power deals in the Marcellus. So this is now our third power deal. We now have access to PJM power pricing and ERCOT power pricing, which we love having in our portfolio.

Derrick Whitfield: Great. And then for my follow-up, I wanted to focus on the Anadarko. While capital costs are down 18% per foot year-over-year, Anadarko D&C is the highest among your 3 assets. If we were to think about a greater capital allocation and/or longer wells in general, how much further could you compress costs if you were to lean into that asset given the constructive gas backdrop we have?

Michael D. Deshazer: Yes. Thanks for that question, Derrick. I think the Anadarko is — it has some huge advantages. One, it’s a pressured basin with really highly productive wells. But that can be a negative on the cost side because they are more expensive to drill, as you’ve pointed out. The lateral length extensions that you see on our upcoming projects will definitely help drive that cost down as well as all of our technology that we’re deploying from the Permian and the Marcellus in terms of getting our facilities costs and our completion costs down. As we continue to run our frac fleet through this 2- and 3-mile project that we’re on right now, we’re excited to see where that could go if we had that consistent frac crew. But in the Anadarko, with the scale of where we’re at right now, we don’t have a consistent crew. And I think that’s another piece of that puzzle that’s missing compared to, let’s say, the Permian, where we have 3 active frac fleets.

Thomas E. Jorden: And I would say, while it may have the highest per foot cost, it also generally over the course of the year has the best price realizations on the gas side for us and the NGL side for us. Ultimately, we always look at returns of these assets, and we think that the returns even at these higher dollar per foot values you see compete heads up with the other basins.

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

Matthew Merrel Portillo: You’ve had some phenomenal success in results in the Dimock box. I was just curious if you might be able to provide some color on how many additional locations do you see in the area and maybe timing of development for those pads moving forward?

Thomas E. Jorden: Yes. We’re — I’ll just answer it this way, Matt. We’ll be Dimock box wells here for the next year or 2. We’re not prepared to give well counts. But they are phenomenal wells. They’re truly phenomenal wells. And the other thing I’ll say is just from a community standpoint, we’re really happy that a lot of royalty owners and landowners that hadn’t been able to participate in the royalties are fully participating. And it’s just nice. It’s nice for the community. So we’ll be drilling in the Dimock box here for the next year or 2.

Matthew Merrel Portillo: That’s great. And then maybe just a follow-up on the Northeast. I was curious if you might be able to talk about your views specifically in Northeast PA on the opportunity set around power demand growth. A lot of your peers in the Southwest PA have provided context in terms of their opportunity set. And then in addition to that, I was curious if you might be able to talk about your updated views on infrastructure opportunities in the region and the ability to potentially market gas further away from the field.

Thomas E. Jorden: Well, I’ll tee that up and Blake will comment. It’s — the opportunity set is rapidly evolving. Now others have said, and we will also say that a long-term commitment at in-basin pricing is not very interesting to us. We have access to in-basin pricing without making long- term commitment. So if we’re going to make long-term commitment to generation — power generation, we’d really like to have some kind of price structure that underwrites that investment. As far as infrastructure, there’s a lot of movement of infrastructure in the Northeast. We are optimistic. But again, we’re going to need to have customers that are willing to make a commitment for the product. We’re just not interested in committing to long-haul transportation without purchasers on the terminus of that, that are willing to have a price that’s constructive. Blake, do you want to add anything to that?

Blake A. Sirgo: I just — on the power side, what’s going on in Pennsylvania is very exciting. We’re seeing lots of movement and all the right players are coming to the table on these things. So the power growth looks real. But I’d just echo what Tom said. It still has to be differentiated for Coterra. We can’t just sign up for long-term in-basin sales. And really, the long-haul projects are the exact same math if we’re going to move gas out of basin and take on those commitments, we need to have either a differentiated price, different market that we really believe in or we need to have a price structure that really helps underwrite those investments that are ultimately going to fill those pipes.

Operator: Your next question comes from the line of Phillip Jungwirth with BMO Capital Markets.

Phillip J. Jungwirth: Can you expand more on the comment about delineation of zones across the Avant acreage, what you’ve derisked to date or could by year-end? And then how does this compare to the acquisition underwriting on the upper end of locations?

Michael D. Deshazer: Yes, this is Michael. Obviously, the Northern Delaware Basin, the main intervals that operators have historically attacked have been in the Third Bone Spring sand and the Second Bone Spring sand. What we’ve seen is a lot of operators have focused that drilling activity in those 2 intervals. We’re excited to see that some of the shallower intervals in the First Bone Spring and Avalon shown tremendous results as you move north. And so that’s — but it’s more geologically driven. In those reservoirs, you have to be more specific about where you’re drilling. It’s not a blanket play. We think that plays to our strengths of being highly geologically driven and that attention to detail where we place our laterals, what spacing looks like, what frac design looks like.

And so that’s what we’re seeing in terms of results there. That’s about as much details we want to get into in terms of what additional ideas we have. Obviously, the First Bone Spring and Avalon are well known at this point, but we’re also excited about other intervals that we see that we’re trying to attack up there as well.

Phillip J. Jungwirth: Okay. Great. And then maybe more specifically on Appalachia marketing. Williams did discuss a new agreement for Northeast Supply Enhancement, which we add $400 million a day to North Jersey and New York markets, more indirectly, but would you see this benefiting Coterra? And then would something like this make constitution less attractive from a producer standpoint?

Blake A. Sirgo: Yes. I mean we’re very involved in all those discussions. I just kind of — whether it’s Constitution or [ NYSE ] or whatever FT deal is, it’s the same math we’ve been talking about. It’s got to provide us either diversity or price enhancement over and above what we can get in the current portfolio. And we’re excited about these deals because that’s bringing new markets to the table, and that’s how we can possibly get some price enhancement in the portfolio. So we’ll see where they go.

Thomas E. Jorden: Yes. [ NYSE ] and Constitution are both top-of-mind items for a lot of people. It makes sense. The way it’s been prioritized is [ NYSE ] has kind of been prioritized above constitution. And the reason for that is [ NYSE ] has more immediate access to a market. There are fewer dominoes that have to fall for [ NYSE ] to make sense. So we’re watching both those with great interest.

Operator: Your next question comes from the line of Paul Cheng with Scotiabank.

Yim Chuen Cheng: Two quick questions. First, based on the comment that you guys made earlier is that means that Anadarko could be an area of interest for M&A?

Thomas E. Jorden: Well, look, Anadarko had some great netbacks. We’re bringing on a project now we’ve talked about in the past that is phenomenally productive from a gas standpoint. You also have natural gas liquids and the profitability is great. We’re in a competitive environment. We’re not going to comment on M&A in any particular area. But we have a great position, great inventory in Anadarko, and it really is a solid part of our portfolio.

Yim Chuen Cheng: And Tom, on the — it looked like that you guys like value the power netback contracts. Is there a target in terms of percent of your gas volume, you would like to be in that type of contracts or that you think higher is better?

Thomas E. Jorden: Well, let me bounce pass that to Blake. We do like power contracts. But Blake…

Blake A. Sirgo: Yes, I wouldn’t say we have a specific target. Really, what we’re always doing with our entire sales portfolio is we’re looking at long- term sales we can take on to give us diversity and price enhancement. And then we’re balancing that with long-term growth plans and how many future volumes we want to commit to these deals. So that’s a very dynamic thing that moves through time. And you’ve seen us step into that more and more, and a lot of that’s underwritten just in the confidence of our assets and deliver these volumes over the long haul.

Operator: Your next question comes from the line of Leo Mariani with ROTH Capital Partners.

Leo Paul Mariani: I wanted to see if you can provide a little bit more color on the Franklin Mountain and Avant acquisitions here. It’s made earlier comments, they’ve been kind of fully integrated. Can you speak and maybe quantify some of the recent results. You talked about testing some other zones there, which sounds encouraging. But can you kind of provide a little bit more of an update on how results have maybe trended on the wells versus the prior operator and how costs have trended versus the prior operator?

Thomas E. Jorden: Leo, thanks for that question. Yes, when we said that the Franklin Mountain and Avant assets are now integrated. What we were really thinking about there is that our field operations, our safety procedures, our rigs and frac crews and everyone’s on the same team now. And that’s really important anytime you acquire assets or a company is getting that culture all the way through that new acquisition asset. In the case of the individual well results, obviously, we had an expectation for all of the wells that were in progress before the acquisition. And all of those wells are meeting those expectations. It’s really about right now where Coterra has been able to put their stamp on all of the well results going forward because we’re getting to choose well spacing and frac design from here on out.

And so our message is that the expectations we had entering into the acquisition, all of those wells that were in progress, we’re meeting or exceeding those expectations. And from here on out, you should expect Coterra results.

Operator: And that is the end of the question-and-answer session. I would now like to pass the call over to Tom Jorden for closing remarks.

Thomas E. Jorden: Yes. I just want to thank everybody for joining us. And in closing, we are on delivering what we promise as always. And when we say consistent profitable growth, you’ve heard us say loud and clear, the growth we’re going to deliver is growth in free cash flow, and we want Coterra to be known as free cash flow machine with great durability. With that, thank you very much.

Operator: This concludes today’s conference call. You may now disconnect your lines. Have a pleasant day, everyone.