Coterra Energy Inc.

Gaffey, VP of Finance, Investor Relations, and Treasurer. Please go ahead.

Thank you, John. Good morning, and thank you for joining Cotera Energy's second quarter 2025 earnings conference call. Today's prepared remarks will include an overview from Tom Jordan, Chairman, CEO, and President, Shane Young, Executive Vice President and CFO, Blake Sergo, 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.

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. Cotera 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 Cotera 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 Harki program. We are on track with our efforts to address the issues that cropped up in our Wyndham Harki flow backs last quarter. We have additional evidence that strongly indicates that the issues we encountered are localized around the Wyndham development and not widespread through our Culberson assets. Blake will give you more details around six new Harki wells recently brought online that are in the immediate vicinity of the Wyndham 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 Plus 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 terrorists, 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 a plan to lay down activity. As we've seen this macro situation stabilized, we have decided to keep nine rigs deployed in the Permian, two rigs in the Marcellus, and one to two 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 three-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 Cotero's differentiating features. Volume growth is an output, not an input. We are bullish on the long-term prospects for our industry and for Cotera 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 two comments. First, although it is inevitable, it will happen to different companies at different times. With our deep inventory of low-cost assets, Cotera is best positioned to maintain its strong capital efficiencies 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 Cotera will be there to help. With that, I will turn the call over to Shane.

Thank you, Tom, and thank you everyone for joining us on this morning's call. Today I'd like to cover three 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, Cotera'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 three 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 nine and three, respectively. We expect tills for the year in all areas to continue to be in line with our annual guidance. Pre-edge oil and gas revenues came in at $1.7 billion, with 52% of revenues coming from oil production. There's 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 67 cents per share and adjusted net income of $367 million or 48 cents 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 MBO 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 frack crew during the quarter. For the full year 2025, we're 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 three 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 tax percentage to move closer to 70 to 90% of total tax expense. With regard to our three-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 in 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. 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 0.5 times 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. Cotera 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, Cotera's team delivered another quarter of high-quality results, both operationally and financially, across all three 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?

Thanks, Shane. On the activity front, we are focused on consistency, which in turn helps optimize our dollar per foot costs and project economics. We expect to maintain nine rigs in the Permian in the second half of the year. which is one rig less than we originally got it to in February. Our current plan allows us to consistently run three frack crews in Permian, including our Culberson Simulfrack fleet, for the remainder of 25 and into 26. In the Marcellus, we have elected to take our second on-ramp and keep two 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 2025 positions Cotera 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 guides. Turning to Culverson County, the Wolf Camp wells at Wyndham 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 row. Remediation efforts on the Wyndham-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 Wyndham-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 pre-drill volumes. Importantly, during the quarter, we brought six new Harkey wells online in Culverson County that were immediately adjacent to Wyndham Row. These wells are in flight while we were bringing on Wyndham Row Harki wells, and we were able to adjust the wellboard 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 Wyndham Row were localized and have been addressed. Across the basin, our broader Harki program continues to perform well. The success of the six new wells in Culberson County reinforces our confidence in the long-term potential of the HARKE interval across the asset. Outside Culberson, we drilled 21 gross HARKE 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 HARKE as a valuable target across the basin for Cotera 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. Cotera is back to consistent work in the Marcellus, with two rigs drilling and one frack crew. We plan to bring on 7 to 12 more tills 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 nine-well project achieved a 30-day equivalent IP of 173 million cubic feet per day. This productivity, paired with strong MGL yields, makes this one of the best gas projects in our portfolio. We continue to gain efficiencies in our Anadarko program with our first three-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 net bag deal in the Permian with a 50,000 mm BTU 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 multi-year 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 net back exposure to Cotera's gas sales portfolio. Similar to our recent LNG transactions, Cotera continues to execute on our strategy of pursuing differentiated gas sales across all of our three 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.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. As a reminder, if you have dialed in and would like to ask a question, please press star followed by the number one on your telephone keypad. And if you would like to withdraw your question, simply press star one again. We kindly ask everyone to limit themselves to one question and one follow-up only to accommodate everyone. Thank you. Your first question comes from the line of Neil Mehta with Goldman Sachs. Please go ahead.

Yeah, thanks so much Tom and team. I I just wanted to start off on on hard key and just you know round round out this this point. It sounds like you feel like you've gotten through through it. So can you just give us a level set of you know how much conviction you have that you've worked through this issue, the timeline and and when do you see production really being at optimal level?

Yeah, Neil, thank you for that question. You know, as Blake said, Our 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 the 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. You know, as Blake said, go forward. It's going to take, you know, 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 Wyndham Row. But we are full steam ahead on Harki and really do look forward to getting this problem behind us.

Yeah, thanks, Tom. 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 grapes kind of around 108 bees right now, which is probably one to two bees 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?

Well, we see, you know, 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, you know, we'd 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 the quality of these wells and the costs that we're bringing this supply on

Blake, you want to comment on that? Yeah, I'll just say that picking the market is a very difficult thing to do with a giant DNC machine. So we're pretty focused on consistent activity. We've really lowered our cost structure in the Marcellus, which has lowered our break-evens, 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.

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 until April and now it's 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.

Your next question comes from the line of Arun Jayaram with JP Morgan. Please go ahead.

Yeah, good morning. Gentlemen, 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 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 or 160. Given Blake's commentary on consistent activity levels, talk to us about you know, 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.

Yeah, 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, you know, solid.

We're going to deliver it. Blake, anything you want to add? Yeah, I'll just say 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.

Yeah, 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.

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

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.

Your next question comes from the line of Doug DeGatte with Wolf Research. Please go ahead.

Well, good morning. I almost didn't recognize your name there. Good morning, Tom. How are you doing?

Very well.

Tom, I wonder if I could ask kind of a high-level question. Forgive me for this, but you're a leader in the industry, and I think your perspective on this can be worth everybody listening to. And it's really in that The industry, you know, 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 destroying price. So it's another way of asking why, I mean, you have the option to not spend $100 million in Marcellus. Is this a desire to maintain production? Because the risk, obviously, to the commodity, As Neil pointed out, production has been surprisingly 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.

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, you know, if we had had this conversation six months ago, I think our conversation would have been very different on gas prices. So I'll just tell you that at Cotera, 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 pricings. I mean, in the case of oil... we'll run it sub $50 oil as if that's the only price that well we'll ever see through its life. And in 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, isn't 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 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. You know, 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 behaviors are representative of the strength of Cotera.

I appreciate the answer. And Tom, I was going to go in a different direction, but I'm going to, if you 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 piers have used that as a crux for managing their tills, almost like seasonally managing their production, shutting it 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?

Blake, why don't you handle that one? Yeah, Doug, you know, 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.

Yeah, 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.

Your next question comes from the line of Betty Jiang with Barclays. Please go ahead.

Good morning. Thank you for taking my question. Shane, I wanted to ask about cash taxes. Thank you for the color you provided earlier. Could 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? Thanks.

Yeah, Betty, thank you for the question. So, look, we are benefiting from two primary things. There's a lot in the bill, but the two primary things are, one, a return 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, you know, 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 two, three, four years, you know, we will get back to where we are. The other thing I would point out on tax and, you know, 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, you know, it really gives us an advantage in 2025. So, again, I would say it's early days as we sort of get through. You know, 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, you know, a range, but a very educated range on a go-forward basis.

So this 80%, can we use that for the next, going forward, that three, five years?

You know, I think 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 three, four years.

My follow-up is on the buyback. With the incremental free cash flow now that 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?

Yeah, that's a really, really fair question. I mean, in 2024, we were about 90% of free cash flow in payout. In 2023, we were probably closer to 76. So we've been at some really elevated levels. We weren't in debt reduction mode. You know, 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, you know, we envision being able to pay off the last 650 of the term loans and at the same time being able to balance that with some buybacks over the course. Now, when we get paid off, so let's say we look into 2026, you know, I think you're spot on that the focus can move back towards buybacks and direct shareholder returns. You know, that being said, you know, 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's been decided yet. But yes, absolutely. I think if you look at the behavior over the last few years in sort of that 75% to 100% range that we've been at, I think when we're out of that debt pay down mode, You know, that's a place that all other things being equal, you should expect to see more buybacks.

Great. Sounds great. Thank you.

Your next question comes from the line with Mizuho. Please go ahead.

Hey, good morning, guys. Thanks for taking my questions. Tom, I want to maybe follow up to Arun's question. You have a pretty strong ramp up in activity 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. I'm not asking for guidance for 2026, but how do you see the trajectory beyond fourth quarter? Do you expect a bit more readable oil volumes in 2026?

Yeah. And then thank you for that. Uh, look, fourth quarter is going to be a bit of a flush. We don't anticipate first quarter being up from fourth quarter, but you know, as 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, you know, we've mentioned working interest, uh, It just so happens that in the fourth quarter, a lot of the contribution is high working interest. So, you know, we're steady as she goes, constant level of activity. But, you know, these kind of quarter-to-quarter fluctuations are just going to be part of the business. But, you know, we want to consistently grow, generate growing free cash flow over the duration.

Great. Thanks for the call there, Tom. 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 three operating areas. 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 sold. should we expect that these new volumes will be really met by sort of a reallocation of InBasin? 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 InBasin as well?

Oh, that's a good question, and I'll answer the first part. Yes, I think of these as reallocation of existing sales. You know, we've We've been on a mission for a while now to diversify away from law. 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.

Your next question comes from the line of Scott Gruber with Citigroup. Please go ahead.

Yeah, good morning. A lot of discussion on the gas strategy. 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 and oil dips back to the high 50s, You know, would the preference be to maintain those nine rigs in the Permian, you know, for that operational consistency? And I assume there's been some good benefit from lower service costs. Or would you look to pivot back, you know, to a lower rig count?

Yeah, I mean, this goes back to what Tom was discussing earlier. 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 costs. And so, you know, assuming we're in a $50 world and not a COVID world, then, yeah, I would expect some consistent activity.

Yeah, 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.

I think also reinvestment rates is an advantage 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 cap capital.

I appreciate that. And then coming back to the Harkey Wells, the new well design you made on the incremental Harkey Wells on Wyndham Row, how much did that cost? TAB, Mark McIntyre, And you mentioned, you know that the water issue doesn't appear to be a an issue across you know the broader call person county. TAB, Mark McIntyre, But what are you thinking about applying that well designed the new enhanced well design across call person out of an abundance of caution or is that not really necessary.

Yeah, 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, you know, 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.

Your next question comes from the line of Cali Acamino with Bank of America. Please go ahead.

Hey, good morning, guys. This first question is on use of cash. You kind of touched on this in your opening remarks. but the term loan is the 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?

Well, look, I'll hit that one. But listen, number one, you know, we've been consistent about the priority and what it's, you know, 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, one, taking volatility out of the system, which we think benefits our shareholders, and then, two, facilitating a return, a more robust and consistent buyback phase, sort of along the lines of what we were discussing with Betty earlier. earlier. So, so we, we see actually, uh, debt pay down is consistent with long-term buyback strategy and getting there as quickly as we can. Now, that being said, you know, we, we, we've talked about having some backend weighted, uh, re repurchases in this year. Uh, if, if cashflow holds up year to date, cashflow has held up. And so that, that, that's good. And to your point at current prices, uh, that, that relative attractiveness, um, it's not lost on us. So, uh, Yeah, so 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.

Thanks, Shane. I appreciate that perspective. My second question is on federal lease sales in New Mexico. Following the big, beautiful 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 point forward?

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.

Your next question comes from the line of David Deckelbaum with TD Cowen. Please go ahead.

Thanks for taking my questions, guys. Just was curious on just how you're thinking about the mid-con in terms of demanding capital over the next couple of years, particularly just given the move into more three-milers this year. How quickly can a three-miler program become part of the mid-con go forward?

You know, I'm going to throw that one to Michael DeShazer, who's over our business units.

Thank you, David. Yes, the three-mile projects are unique in that a lot of the development is already in place in Pena Field, where we operate in our three 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 three-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 two miles in the past, we won't be able to move all of that program to three miles over time.

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

No, I mean, that's why we really, you know, 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. So we de-risked those volumes this year, and we'll see how they clean up through time.

Your next question comes from the line of Derek Whitfield with Texas Capital. Please go ahead.

Thanks. Good morning, all. Congrats on your update. With my first question, I wanted to lean in on the power jet opportunity for Katerra and the success you've experienced in achieving power sales agreements. As this has been an elusive feat for many of your Permian peers, how would you characterize what's leading to your success and how you're positioning Katerra as a partner?

Yeah, thanks, Derek. A lot of really hard work is really the only answer to that question. Our marketing team talks to lots of folks. We talk 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. 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 two 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.

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 past the initial conversation. 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, you know, another element of this that hopefully is not lost is the access to power. You know, 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.

Yeah, just as a reminder, we have two great power deals in the Marcellus. This is now our third power deal. We now have access to PJM power pricing and ERCOP. pricing, which we love having in our portfolio.

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 three 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?

Yeah, I think for that question, Derek, 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 linked 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 two and three 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 three active frack fleets.

And I would say, you know, 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.

Your next question comes from the line of Matt Portilio with TPH. Please go ahead.

Good morning, all. You've had some phenomenal success and results in the DEMIC box. I was just curious if you might be able to provide some color on how many additional locations you see in the area and maybe timing of development for those pads moving forward.

Yeah, we're, um, you know, I'll just answer it this way, Matt, we'll be, we'll be drilling Dimock box wells here for the next year or two. Uh, you know, we're not prepared to give well counts, but they are phenomenal wells. They're, they're truly phenomenal wells. And, you know, the other thing I'll say is just from a, 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 Dimmock box here for the next year or two.

That's great. And then maybe just to 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 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.

Well, I'll see that Blake will comment. You know, 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 you know, have a price that's constructive. Blake, you want to add anything to that?

I just, you know, 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 Cotera. 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, a 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.

Your next question comes from the line of Philip Youngworth with BMO Capital Markets. Please go ahead.

Thanks. Good morning. Can you expand more on the comment about delineation of zones across the Avant acreage, what you've de-risked to date or could by year end, and then how does this compare to the acquisition underwriting on the upper end of locations?

Yeah, 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 two intervals. We're excited to see that some of the shallower intervals in the first bone spring and Avalon have shown tremendous results as you move north. 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 of where we place our laterals, what spacing looks like, what frack design looks like. And so that's what we're seeing in terms of results there. That's about as much detail as we want to get into in terms of what additional ideas we have. Obviously, The first-month 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.

Okay, great. And then maybe more specifically on Appalachian marketing, Williams did discuss a new agreement for Northeast Supply Enhancement, which would add $400 million a day to North Jersey and New York markets. More indirectly, but would you see this benefiting Cotera and then Would something like this make Constitution less attractive from a producer standpoint?

Yeah, I mean, we're very involved in all those discussions. You know, I just kind of, whether it's Constitution or NESE 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.

Yeah, you know, Nessie and Constitution are both top-of-mind items for a lot of people. It makes sense. The way it's been prioritized is Nessie's kind of been prioritized above Constitution. And the reason for that is Nessie has more immediate access to a market. You'd There are fewer dominoes that have to fall for Nessie to make sense. So we're watching both those with great interest.

Your next question comes from the line of Paul Chang with Scotiabank. Please go ahead.

Hey, guys.

Good morning.

Two quick questions. First, based on the comment that you guys made earlier, does that mean that Anadarko could be an aerial interest for M&A?

Well, look, Anadarko has some great netbacks. You know, 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, you know, the profitability is great. You know, 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.

And, Tom, it looks like you guys like the power netback contracts. Is there a target in terms of percent of your gas volumes? you would like to be in that type of contracts or that you think higher is better?

Well, let me bounce past that to Blake. We do like power contracts, but Blake.

Yeah, 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. And 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.

I see. Okay, we do. Thank you. Your next question comes from the line of Leo Mariani with Roth Capital Partners. Please go ahead.

Yeah, hi. I wanted to see if you can provide a little bit more color on the Franklin Mountain and Avant acquisitions here. You've made an earlier comment. 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 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?

Hey, Neil. Thanks for that question. Yeah, 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 frack crews, and everyone's on the same team now. And that's really important any time you acquire assets. 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 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 we're Cotera 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 Cotera results. Thanks. Thanks.

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

Yeah, I just want to thank everybody for joining us. And in closing, you know, we're working on delivering what we promised, 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 Cotera to be known as free cash flow machine with great durability. With that, thank you very much.

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