Infinitytural Resources Inc Cla Aktie

Hello, everyone. Thank you for joining us, and welcome to Infinity Natural Resources Third Quarter 2026 Earnings Call. [Operator Instructions]

I will now hand the conference over to Tom Marchetti, Vice President of Investor Relations. Tom, please go ahead.

Thank you, operator. Good morning, and thank you for joining Infinity Natural Resources Third Quarter 2026 Earnings Conference Call. With me today is Zack Arnold, our President and Chief Executive Officer; and Cary Baetz, Infinity, Executive Vice President and Chief Financial Officer.

In a moment, Zack and Cary will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations section of our website, and we may reference certain slides during today's discussion. A replay of the call will be available on our website later today.

Before we begin, I would like to remind everyone that today's call may contain forward-looking statements. All statements that are not historical facts are forward-looking statements. Forward-looking statements are subject to a number of risks and uncertainties many of which are beyond our control that could cause actual results to differ materially from these forward-looking statements.

Please review our earnings release and the risk factors discussed in our SEC filings. We will also be referring to certain non-GAAP financial measures. Please refer to our earnings release and investor presentation for important disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures.

With that, I will turn the call over to Zack.

Thank you, Tom, and hello, everyone. We appreciate you joining us to review Infinity Natural Resources third Quarter Results. We are almost 3 quarters since closing our Ohio acquisition, and it is a good moment to take stock. The assets are integrated into our operations. We are growing production. We are putting more volume through our midstream system, and we are delivering the synergies we outlined.

Just as important, we have the team, the balance sheet and the platform in place to act on the next opportunity that meets our underwriting criteria. That progress is visible in our third quarter results, where we continue to execute on our playbook and delivered both record production and adjusted EBITDAX.

In the third quarter, our oil volumes came in ahead of our expectations, increasing 79% year-over-year to approximately 14,000 barrels per day. Our total volumes averaged nearly 432 million cubic feet equivalent per day, which is a 100% increase from the prior year. Higher volumes and a favorable oil mix drove adjusted EBITDAX of nearly $138 million. We also brought our controllable cash costs down sequentially on a per unit basis. Consistent with expectations, our per unit GP&T costs declined as more volumes moved through our own midstream system.

On the marketing front, our REX Zone 3 contract is starting to highlight its value. Most of our Ohio gas and over half of our total gas is sold into markets served by this pipeline, which we expect to give us a meaningful uplift relative to local in-basin pricing. As we continue to develop our portfolio, we remain very encouraged by the opportunity to scale our upstream assets on a midstream system with substantial available capacity. The system has approximately 1 bcf per day of throughput capacity, enough to support our organic growth with room for third-party volumes as well. About 70% of our gross operated natural gas volumes already flow through it and utilization of almost 35% continues to move higher with incremental volume lowering our per unit cost. That capacity gives us a long runway to grow, both organically and through strategic acquisitions that add volume to the system and lower our cost structure.

Our conviction in the long-term value of these assets continues to strengthen. Taken together, our strategy remains unchanged. We continue to execute the disciplined growth plan we have outlined, scaling production, increasing utilization of our integrated midstream system, maintaining capital efficiency and lowering controllable costs, all while focusing our capital on our highest return opportunities.

As you saw in our earnings release, we now expect to spend at the lower end of our capital guidance range and to produce at the higher end of our production guidance range for 2026. Both are within our initial 2026 guidance ranges. We have continued to be efficient with capital allocation even as cost pressures increased primarily from diesel and stimulation cost increases while delivering a higher liquids mix. We took advantage of our flexible portfolio by reducing gas development and increasing oil development in a very favorable oil price environment to drive record adjusted EBITDAX.

Turning now to a summary of our third quarter operations. Our field and operations teams had a very productive third quarter, and I want to thank them for the work behind these results. We have continued to deliver strong operational execution with optimized laterals and consistent in-zone geosteering, which increased reservoir exposure and value capture per well. We recently drilled our longest lateral at nearly 24,000 feet, all of which was done with a single bit.

On to the deep dry gas Utica. Recall that we spud our well in the second quarter and then in mid-October, we concluded stimulation activity. We've taken a measured pace to collect subsurface data along the way, including full core analysis across the entire Utica and Point Pleasant [ formation ] . We look forward to bringing the well online and sharing more information in due course.

Turning to synergies. For 2026, we expect to capture more than our previously announced $25 million of cost and capital savings. We are developing the Utica assets we acquired earlier this year with our own operating model on pads and midstream infrastructure that are largely already in place, and that is where the benefits of the acquisition began to show up. The largest contributors have come from development optimization. By drilling from existing pad locations and redesigning wellbores, we eliminated vertical sections, their associated production equipment and the construction of multiple new pads. That also removed the facilities, pipeline interconnects and waterline interconnects those pads would have required, all with a rig move and the related trucking. We also connected our existing water withdrawals to the acquired water delivery system, which lowers our per barrel water cost across this year and the future completions.

We believe that our REX contract will be a meaningful contributor. When you look at the basis differential between M2 or Dominion South and REX Zone 3, the firm transport capacity we acquired on REX to Zone 3 should be a valuable asset. It gives us more marketing flexibility and should improve our natural gas realizations. We added a new slide to our earnings deck that helps explain this competitive advantage.

Beyond acquisition-related synergies, we continue to find ways to lower CapEx and improve returns across our operations. Within completions, we are reducing costs by optimizing our completion fluids design by field.

On the production side, we have been able to improve well returns by installing capillary strings as an alternative to production. Given the cost inflation in 2026, we are further evaluating ways to reduce our diesel cost exposure, including dual fuel utilization on our drilling rigs and frac fleets. Ultimately, our plan is built on returns. We have a diversified portfolio of projects that clear our return thresholds, giving us the flexibility to adjust activity as returns dictate as we have shown in the past.

Development remains our first priority for capital, followed by acquisitions and leasing, where we look for opportunities that deepen our drilling inventory, add scale and put more volume through our midstream system. We stay disciplined, putting every opportunity through a rigorous evaluation and letting capital follow returns, not commodity prices.

With that, I'll turn the call over to Cary.

Thanks, Zack. I'm delighted to join you for my first earnings call with INR. I have very much enjoyed my first couple of months in the seat and working alongside a great group of colleagues. As we look ahead, an important priority will be continuing to build on the strong financial foundation we've established and ensuring our organization is positioned to support the next phase of growth.

To that end, we've added depth to our leadership team with the addition of an SVP of Finance and a VP of Corporate Development, while continuing to evolve our financial processes and capabilities as the business scales. Alongside organic growth, strategic acquisitions remains a core component of our long-term strategy. Having the right team and capabilities in place is critical to executing that strategy successfully. Our focus will remain on pursuing opportunities that enhance the quality and scale of our asset base while maintaining the financial discipline that protects our balance sheet and preserves a clear compelling investment thesis. We also recognize the importance of scale, not only in driving greater operating efficiencies and economies of scales, but also in expanding our public float and improving the accessibility of our shares to a broader institutional investor base.

Ultimately, our objective is to grow thoughtfully, maintaining financial flexibility and continuing to build a business that can deliver sustainable value for our shareholders.

Turning to our results. Third quarter adjusted EBITDAX was $138 million or $3.47 per Mcfe compared to $3.62 per Mcfe in the second quarter. Higher volumes, a favorable liquids mix and relatively strong realizations, higher utilization and lower per unit costs all contributed. We saw our controllable cash cost decline 8.2% sequentially from $1.58 per Mcfe in the second quarter to $1.45 per Mcfe in the third quarter. This reflects the structural advantage of our integrated midstream system and the meaningful operating leverage of our platform.

As production volumes grow, we are leveraging existing infrastructure and available capacity to drive greater efficiencies with midstream utilization increasing from 29% in the second quarter to approximately 35% in the third quarter. Importantly, GP&T expenses per Mcfe declined 12% sequentially even as liquid productions increased. Our ability to reduce GP&T expenses per Mcfe despite this inherent cost headwinds demonstrates the differentiated value of our integrated midstream system and reinforces our ability to expand margins as production continues to grow.

Now turning to the balance sheet. We ended the quarter with net leverage of 1.1x. We have no near-term debt maturities and no borrowings outstanding under our revolver credit facility at the end of the quarter. We ended the period with approximately $900 million of liquidity. We also recently completed our fall redetermination with our bank group with our borrowing base being reaffirmed.

Turning to risk management. Our hedging philosophy is unchanged. We hedge at the project level, and we do so methodically to help ensure that we can deliver on all of our growth plans. Our focus remains on project returns while using hedges to protect our cash flows. As a result, our returns are less sensitive to commodity price movements, and we have strong visibility of our cash flows to support our organic growth plan.

Finally, on 2026 guidance, we have narrowed our guidance and now expect net production to fall in the high end of the range and average between 355 and 375 MMcfe per day. Similarly, we expect development capital expenditures, which are a combination of drilling and completion and midstream capital expenditures to be in the range of $450 million to $475 million. That's it for me. And now back to Zack to conclude our opening remarks.

Thanks Cary. Before we open the line, I want to leave everyone with a few key takeaways. We've spent a lot of time this year talking about the opportunity embedded in our platform and the value we believe we can unlock through disciplined execution. So we have told you previously what to expect from this business. And this quarter, we delivered it. We demonstrated our ability to improve the performance of the upstream assets we acquired while working on maximizing our midstream infrastructure to drive down per unit cost and capture stronger realizations through our firm transportation capacity. All of this translated to record production and adjusted EBITDAX.

And most importantly, we continue to build a team that focuses on safety, efficiency, growth and value creation. These results reinforce the differentiated value of our integrated growth-focused platform, and we're just beginning to unlock that potential. We're going to continue to let our execution and results speak for themselves.

Operator, you may now begin the Q&A session.

[Operator Instructions] Your first question comes from the line of Scott Hanold with RBC.

It looks like that midstream is starting to really show the value. And so it looks like that utilization of both REX contracted infrastructure keeps increasing. Could you give us a little bit of color on as you enter the winter, your ability to kind of scale that utilization to premium markets? And what does this do to realizations and GP&T costs? If you could just give us a sense of the range of potential outcomes and benefits there.

Yes, Scott, this is Cary. There are a couple of questions there. Let's see if I answer them all. And if not, Zack will fill in the rest. But I think from a REX point of view, the idea is going to maximize the value of that contract. We are doing so today. We look to be doing that for the foreseeable future. Obviously, you can kind of see on a daily differential, the improvement pickup we get with that contract. It can cover roughly north of 10% of our total production volume on a gas basis point of view. So it is meaningful across the board.

From a GP&T point of view, it doesn't have a substantial impact on that. I think more importantly on GP&T, it's really where are we producing, what's the volume coming out. If we're heavier on oil or liquids, obviously, GP&T expenses go up. If we're heavier on dry gas, we'll see GP&T expenses go down. So I think really, that can be variable on a quarter-to-quarter basis depending where our volumes are. But overall, I think, again, the REX contract has been very good. It's been very accretive to us. We'll continue to maximize that until we start seeing in-basin differentials getting to a point where that contract is probably not as strong as it was. But today, it's meaningful to us. Did I get everything, I think, Scott?

Yes. Just kind of curious if you could kind of range bound the potential benefits into the winter, what you're seeing today given the spreads.

I think from a -- on a net-net basis, if you count an idea of including transportation costs, you're probably looking somewhere between 15% to 25% net pickup improvement versus in-basin when you count transportation on that as well. So carrying that through throughout the quarter. Obviously, we're seeing in-basin differentials for the winter months coming down. So that narrows the gap a little bit. But I think 15% to 25%, or $0.25 per is probably a decent enough range.

Appreciate that context. And as my follow-up on production, you obviously raised to the high end of your full year guidance, but you did outperformed quite a bit in 3Q. And I guess the implied 4Q was a little bit soft relative to Street consensus. Can you give us a sense of some of the moving parts on that? Is that just timing of the TILs that you did in 3Q impacting 4Q?

Yes. I think -- that's a great question. This is Zack. When we started reconsidering our development schedule early in the year to react to oil price movement, that just has a little bit of a ripple effect on turn-in-line timing.

And in Q3, we really saw the benefit of full quarter contribution from early quarter turn-in-lines. Q4, we haven't had our turn-in-lines yet. They will come in at the back of the quarter, and they'll have some ramp-up period. So as we evaluate our individual well results, we continue to be very pleased as they meet or exceed our expectations. A company our size is always subject to timing, and we're really grateful that we were able to deliver the production, the way we have to date and our updated guidance reflects that. And anything that you're seeing in a Q4 dip is just related to timing.

Your next question comes from the line of John Annis with Texas Capital.

For my first one, maybe for Cary, you're stepping into the CFO role as the company is delivering strong production growth and cost reduction. And now that you've had some time in the seat, I'm curious where you see the greatest opportunities to improve, I guess, the financial strategy? And is there anything that you expect to emphasize or focus on differently going forward?

John, yes, great question. Again, Zack and the team have done a great job of building a long-term sustainable business. I think a lot of it has to do with moving fast. And with moving fast means there are some things that get left behind. We're working on improving processes. But I think probably more importantly is focusing on data, quality of data and getting them better dashboards so we can do things on a more proactive basis and giving them visibility so we can make better business decisions quicker.

So I think that's going to be the biggest key. That will provide us more efficiency in the business, hopefully driving down costs, reducing -- there's times where we have a rig sitting for a couple of weeks as we're moving things around and all that. So getting things like that lined out will improve efficiency, drive down the cost. But I think it's really visibility of the information to make better decisions on a proactive basis is one of the key items we're focused on now.

Obviously, we talked about, we're building up the team to help us on the corporate finance side and the business development side. So we can get things where we're really looking at everything that we're prioritizing what we're looking at. We're really driving down on how you create the value, where the value drivers are, how that helps us not only on an existing production, but helps us on the inventory side of the equation. So I think overall, from the accounting visibility side of the equation, I've talked about and then on business development and all that is just being able to things, do things where we're not just running in a hamster wheel, but we have things in a much more linear fashion where we can react quicker and also have the capital to be able to move those in -- move those quickly and give us a competitive advantage.

Got it. I appreciate that color. For my follow-up, looking beyond the acreage bolt-ons, what opportunities do you see to extend laterals and expand the inventory through either step-out drilling on existing pads, U-turns that some of your peers have highlighted this quarter or other initiatives? And could any of those move current subeconomic locations into the development plan?

Well, that's a great question. Thanks for asking it. I'll take it probably, touch on the first question a little bit and then spend a little more time on the second part. But when you think about lengthening laterals, that is something that we think our ground game is really strong at delivering. That comes either through leasing, and we see opportunities to do that, and we've got some things in front of us today. But that also can come through trades. And as we continue to develop stronger and deeper relationships with our peers in the basin, trades can really help us optimize those laterals, too, because we've seen that the operations team can execute 24,000-foot plus laterals. So that really allows us to continue to lengthen inventory that might be less economic than a longer well, particularly as we've seen some upward pressure on service costs with diesel and other things.

But as far as some of the U-turns and other things, we demonstrated in the script and on the -- in the slides, some of the synergies that we are delivering from the Antero acquisition that we did. And I think that really starts to drive home some of the points that you were making. And our team wants to be fast followers and quick adopters of technology and all of those things have converged for some real savings here in Q3 and into Q4. We've already eliminated 2 pads from the construction that would have been necessary with the legacy development plan. That elimination of construction also means for us because we control the midstream, the elimination of pipelines and water lines and facilities and especially when you get into these liquids-rich areas, those facility costs can be quite expensive.

And then also the rig mobilizations that can come when we're able to use the same rig, on the same pad we're already deployed to drill wells adjacent to us. And all of that is done with improvements to safety, environmental timing, all those risks go away when we're able to do what we delivered on this last quarter, which is developing 3 wells that we were excited about drilling and noticing that adjacent to that was a unit that was planned to be developed with shorter, less economic wells.

So instead of building a new pad, tying a pipe and drilling 4 wells that would have been suboptimal from a lateral length, we drilled 2 U-turns off of an existing pad and we did capture that in a much more capitally efficient manner. So all of that combines to demonstrate that we are going to exceed the $25 million of synergies we identified, and we see lots of opportunities in the future as we rethink the development of this field and other fields as we continue to look across the M&A landscape.

Your next question comes from the line of John Freeman with Raymond James.

I just want to follow up on Scott's earlier question on REX. I appreciate the marketing slides and the presentation. So it looks like just sort of backing into the third quarter REX sales that you are utilizing just over half of that 300 that you've got on the FT on REX. Is the remaining capacity all available to accommodate all incremental volumes? Or were there any pre-existing sort of third-party arrangements when you all acquired the Antero assets?

Yes, they were third-party arrangement. So we're able to either fill that with our own volumes or work with gas marketers to fill shortfalls that we've had in the early stages of our development cycle. But we anticipate that we'll be really maximizing that usage in 2027.

Got it. And then my follow-up on Slide 11, you detailed all the meaningful improvements you all had on the drilling completion side on lateral feet drilled per day, the pumping hours per day. On the well cycle times, I'm assuming that 2026 relative to '25 is just impacted by larger pads. If that's true, can you just sort of maybe quantify sort of that difference in this year versus '25 and then maybe what you all are anticipating for kind of pad sizes in '27?

That's a great catch there. And I wondered if someone was going to see we had a small tick up in cycle time. So thanks, John, for highlighting that. We -- I think what you saw there was a little bit of pad well count, but it's also a function of facilities. When we have more and more of these volatile oil wells like we've shifted to in 2026, it takes a little bit longer for us to have some of the facilities and some of the things put into place. So we're still very proud of the work that the teams do to minimize those. I think we can deliver really efficient cycle times. But occasionally, we -- a project takes a little bit longer because of just the amount of equipment that's required.

Your next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

I want to start and kind of follow up on the REX discussions. Maybe this is for Cary. As you settle in the role here, we can see sort of the benefits to realizations from the Antero acquisition in the FT. Can you talk about any other sort of aspirations you have to sort of support marketing efforts to further drive realizations? Is there anything you see on the horizon? Or do you think just maximizing that FT is the majority of the opportunity in the near term?

Yes, Tim, I think in the near term, obviously, maximizing, but then you have the power gen side of the equation that will be something that I think people will be looking forward as we go into '27, '28 and '29. So -- nobody knows what's going to happen around the data center side of the world and all that. But again, I think you'll still see capacity coming online. It may not be as enthusiastic as people originally thought, but I think you're going to see a continued increase in power gen, and that will provide us more opportunities in basin to be able to maximize.

Okay. So you're starting to look into those now. Is that what you're saying?

Yes. Yes, sir.

Okay. I appreciate the context. And then as my follow-up, when you all hosted everybody last month at your sell-side rig tour, I believe the commentary was that you're open to increasing your footprint anywhere within that sort of area, that Ohio, West Virginia, Pennsylvania area. So maybe, Zack, can you talk about kind of what you're seeing from an M&A perspective, maybe looking at the gas and the oily acreage separately?

Great question, Tim. Thank you. And I think first and foremost, before you get into M&A deeply, you need to make sure you have the balance sheet in place, and Cary has been helpful in managing that and also the team to evaluate it. Cary talked in his opening remarks about some of the expansion we've had at that team level to make sure that we have the right people in the right places to help us analyze things because we have a benefit at INR in that we have an operating experience across the entire basin. We're somewhat agnostic as to where the deals fall, but that also means we need to be able to analyze and evaluate things across the entire basin quickly.

And Cary touched on systems and processes. And I think we're going to be focused here near term on making sure that we can evaluate deals faster than our competitors and make sure that we can do deals that work well for us. And for us, it needs to be accretive on a long-term basis, and it needs to stack in well and help us with either production volumes or inventory depth or midstream utilization. And now that we've got the midstream piece, it gives another flavor to consider when we evaluate M&A.

But as far as where we see deals going, this basin is always a little bit interesting when you see the deal pipeline, but we'll continue to participate in public processes across the entire basin, oily or gas. And we'll also look for private processes where we can maybe find an asset that is a better fit for us than the current owner and see if we can negotiate something there. But in the meantime, we remain poised and ready, and we will be very conservative in our underwriting cases to make sure that the investments we make are not scale for scale's sake, that it is going to be accretive to our shareholders.

Your next question comes from the line of Michael Scialla with Stephens.

Zack, you mentioned in your prepared remarks about some expectations on inflation, diesel. And I think you said stimulation costs moving up. And you also mentioned you're looking at potentially dual fuel rigs and fleets. Just want to see what you're thinking, if you could throw out any numbers in terms of even high-level inflation for next year that we should be thinking about and where you stand with getting those e-fleets or dual fuel rigs?

Great question. And I think it's somewhere we're focusing a lot of energy as we wrap up the year and are focused on the 2027 budgeting cycle. I give the operations team a ton of credit because we were able to reduce the high end of our CapEx guidance despite these issues that are prevalent in the market. I think if you ask people for the top 3 impacts on costs, it's diesel, diesel and diesel. And as such, we're curious as to what the diesel pricing will do into 2027. But we've told the team that their job is to counteract that through efficiencies and through optimization of processes, and they've answered that well so far.

So I think we're optimistic that we'll minimize those impacts into 2027, and we are now at a scale in which we can negotiate longer-term contracts with people, that will help, and we're finalizing those. I can't give specific guidance on what type of budget impact that will have. But I can say that we're very well positioned to counteract the market forces here while we continue to optimize and become more efficient with our development program.

Sounds good. And just, I guess, staying on thoughts on next year. Should we be thinking about something similar at this point? I realize it's too early to give guidance, but something similar from a high level to the 2 rig plan that you're running this year for next year? And I guess along that, too, is the deep Utica going to be part of the '27 plan? Or do you need to just kind of watch this well and watch where gas prices go before you make a decision there?

Yes. Mike, this is Cary. I'll take over at least the first part of that, and I'll dive into the second part of it. But the answer right now is, I think from a modeling point of view, I would continue to see -- look at '27 to be similar to '26 at this point in time. Obviously, we're still in the budgeting process. So I don't want to get up and over our skis. As Zack just pointed out, I think the other thing we need to think about is where does cost inflation versus efficiency. But I think right now, we do think efficiencies can offset most of the cost inflation that we're going to see on the service cost of the equation.

From a deep dry gas Utica point of view, obviously, we're very excited about that well coming online. I think your second part of that question was correct. I think depending on how the outlook is for gas prices for '27 will impact the timing of the next wells coming online. We're not looking to curtail anything that we can curtail through our CapEx dollars and the timing of our CapEx dollars based on it. But again, we're very optimistic and excited about that well coming online.

Also from an online point of view, we have, I think, 66 locations. So we get to 65 more locations, which obviously is a meaningful addition to our inventory and our NAV, and those are other things that we're looking at from that opportunity as well. But I don't know, Zack, do you want to add anything to that?

No, you covered it.

Your next question comes from the line of Paul Diamond with Citi.

So earlier this year, you guys shifted a bit more towards the oil side versus gas on production timing. Given current market realities, can you talk about any shift you're seeing? Is there anything in the market that would make you kind of shift backwards? Or is this cadence kind of what we should carry it forward?

Great question, Paul. Thanks for asking that. It's good to connect this morning. I think, obviously, our cadence for 2026 is established and set in stone. As we look at 2027, things change quickly. There are world factors that impact commodity prices. So we're taking that into consideration as we finalize our budget and our development views for 2027.

I think generally speaking, what we've approached in the past is starting from a place of balance in which we develop both oil and gas locations. And then you might see us tilt a little bit and try to optimize whichever commodity we think we can hedge and be a little bit stronger. So year-over-year, we may be a little bit less flexible as we just get bigger and each of those projects have a smaller impact. But for today, we're happy with the way we allocated capital in 2026, and we're actively reviewing the 2027 development program to make sure that we can optimize shareholder value.

Paul, this is Cary. I'll add one comment on to that. The 2027 budget is going to be a little different budgeting cycle for us. We are building up from a bottoms-up looking at each project on an economic basis. So I think we're really going to be economics driven from our 2027 budget. So -- and that may change how we allocate the capital based upon the economics of each individual project. So I think once we get into a '27, we'll have a pretty good outlook of what we're going to do for the year, where we're going to do it. And obviously, from our hedge book point of view, it gives us some flexibility as well from visibility to the cash flows. But I think a little different budgeting cycle than what we've done in the past. And it gets back to my early comments about better data, better transparency, visibility and proactive for the business. So I think those are the things that we're working on.

Got it. Appreciate the clarity there. Just one quick one on -- you just talked about Utica development a bit over the last several quarters. You talk about any design differences versus the prior operator? Is it -- I know you talked about mainly proppant loading, but has there been any other, I guess, lesson learned with a couple of quarters under your belt?

Yes. And if you're focused specifically on the acquired Utica assets, I think we were basically backing up and taking a fresh view of the asset in the right way to develop it. So today, what we've delivered on so far are a couple of U-turn wells that we think were the most capitally efficient way to develop some adjacent somewhat stranded acreage. So I think that's a place where we've seen capital savings. I think we've also -- so that's a savings component. I think we're also investing more in some of the completions than the legacy operator did where we've increased water per foot and sand per foot. So sometimes you spend more to make more, and that's the case there.

And what we are demonstrating on Slide 12 was really our ability to do that more intense stimulation design but do so faster than the previous operator. So it puts us in a position in which we can do more in fewer days and really help us tighten up those cycle times. But we acquired those assets from a world-class operator. So that means there's some things that have been done very well. We're just able to take a fresh view and look for some opportunities to optimize casing designs and completion designs to make the projects our own.

We have reached the end of the Q&A session. I will now turn the call back to Zack Arnold for closing remarks.

Well, thank you all for another quarter here at INR. We appreciate your continued interest and investment in our company, and we look forward to catching up again next quarter. Thank you.

This concludes today's call. Thank you for attending. You may now disconnect.

Hello, everyone. Thank you for joining us, and welcome to Infinity Natural Resources' Second Quarter 2026 Earnings Call. [Operator Instructions] I will now hand the conference over to Tom Marchetti, Vice President of Investor Relations. Thomas, please go ahead.

Thank you, operator. Good morning, and thank you for joining Infinity Natural Resources' Second Quarter 2026 Earnings Conference Call. With me today is Zack Arnold, our President and Chief Executive Officer. In a moment, Zack will present his prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations section of our website, and we may reference certain slides during today's discussion. A replay of today's call will be available on our website beginning this evening. Before we begin, I would like to remind everybody that today's call may contain forward-looking statements. All statements that are not historical facts are forward-looking statements.

Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from these forward-looking statements. Please review our earnings release and the risk factors discussed in our SEC filings. We will also be referring to certain non-GAAP financial measures. Please refer to our earnings release and investor presentation for more important disclosure regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Zack.

Thanks, Tom, and good day, everyone. We're glad to have you with us to review Infinity Natural Resources' second quarter results. It was a busy and productive quarter for our team, and I want to start by thanking everyone at Infinity for the work that went into it. Before we get into our operational and financial results, I'd like to spend some time discussing the changes in our leadership. As we announced yesterday, David Sproule will be stepping down as our Executive Vice President and Chief Financial Officer. David is one of the founders of Infinity, and we would all like to thank David for his dedication and passion to Infinity.

I would also like to take this time to welcome Cary Baetz and Andrew Judge to Infinity Natural Resources. Effective August 12, Cary will be assuming the responsibilities as Executive Vice President and Chief Financial Officer, and Andrew will add a layer of expertise to our existing team as Senior Vice President of Finance.

Cary has a strong track record of raising capital, leading companies through significant transactions, and building the financial infrastructure to support the kind of growth we expect. Andrew brings deep in-basin upstream expertise and a proven ability to secure capital, evaluate M&A opportunities, and build strong investor relationships. We are excited to have both executives join our leadership team and, together with our recently expanded Board, continue building the organizational depth and leadership necessary to execute on our long-term strategy.

Now let's move on and discuss our results. The second quarter reflected continued execution of our strategy. We delivered strong production growth and our highest quarterly adjusted EBITDAX in company history at $115 million. In addition, we transitioned from integration to active development of our recently acquired Antero assets, bringing our first wells online and beginning drilling operations on a second pad during the quarter. We have recently completed drilling the second pad and have begun drilling on a third pad. Now more than a full quarter into owning these Ohio Utica assets, we remain very encouraged by the potential to scale the upstream assets with what has been an underutilized midstream system. As we continue integrating these assets, our conviction in their long-term value only continues to grow.

Our strategy remains unchanged. We continue to execute the disciplined growth plan we have consistently outlined by scaling production, increasing utilization of our integrated midstream assets, maintaining leading capital efficiency, and lowering controllable costs. At the same time, we continue to evaluate M&A opportunities that strengthen the platform and enhance its long-term cash-generating capacity.

Turning to our production and operational execution during the quarter. Net production averaged 348 million cubic feet equivalent per day, a year-over-year growth rate of 75%. We brought a total of 10 wells online in Ohio, including the first 3 rich gas wells from our Antero acquisition and 7 other volatile oil wells. On the operating front, we spudded 9 wells, including 4 volatile oil wells in Ohio, 2 rich gas wells in Ohio, 2 dry gas wells in Pennsylvania, as well as our first deep dry gas Utica well in Pennsylvania. We drilled a vertical pilot on the deep dry gas Utica, collected subsurface data for analysis, and drilled a 9,500-foot lateral.

We continue to evaluate the results of the core and data we collected to refine our technical understanding, and we look forward to sharing more with you in the future. In terms of execution, our operations team continues to raise the bar. During the second quarter, we delivered another step change in drilling and completion efficiency, increasing lateral feet drilled per day by 15% compared to our 2025 average while maintaining 100% in-zone geosteering accuracy. We also successfully validated a revised completion design that reduced completion costs by $50 per foot in Guernsey County through higher proppant loading, extended stage spacing, and reducing the number of frac stages.

These operational gains improve capital efficiency, accelerate cash flow generation, and reinforce the scalability of our integrated Appalachian development platform. As we look to the third quarter, we expect to turn in line 7 wells. This includes a 4-well pad we expect to turn in line in the coming days in the volatile oil window and a 3-well pad we turned in line in mid-July in our dry gas-weighted Pennsylvania Marcellus acreage.

Our diversified portfolio provides the operational flexibility to allocate capital to the highest-return opportunities. Our midstream infrastructure will play a critical role in the reduction of our per-unit costs as we increase system utilization. Since the end of the first quarter, our system utilization has increased approximately 30%, with approximately 70% of our current gross natural gas production flowing through our wholly owned, low-cost system today. We now have approximately 1 Bcf per day of gathering capacity across our integrated midstream system, including roughly 400 million cubic feet per day of capacity in Pennsylvania and 600 million cubic feet per day in Ohio.

This system is currently operating at approximately 35% total utilization, providing significant capacity to support future production growth without meaningful incremental infrastructure investment and an opportunity to attract third-party volumes. The strategic value of our midstream system extends well beyond its current utilization. Replicating a comparable footprint today would require substantial capital, long equipment lead times, and significant execution.

This infrastructure also allows us to market our production more effectively. Today, our premium market access on the gas side is largely tied to REX Zone 3. As additional in-basin sinks continue to develop, we expect to diversify the markets where we sell our gas products. Our dual-commodity strategy across Ohio and Pennsylvania gives us the flexibility to direct volumes to whichever markets and end customers make the most sense. On the liquids side, we continue to see growing optionality with end customers. And as our volumes scale, and we bring more marketing functions in-house, we believe we have an opportunity to capture additional margins over time.

Starting in March, we began taking in-kind the majority of our propane, butane, and pentane products. We've recognized an uplift in propane price realizations over prior periods.

Now, getting into more operating details and our financial performance. During the second quarter, our net production averaged 348 million cubic feet equivalent per day. Oil production totaled approximately 12.4 thousand barrels per day for the quarter, up 102% year-over-year. Natural gas production averaged approximately 217 million cubic feet per day, up 73% year-over-year. And NGL production increased 57% year-over-year to approximately 9.5 thousand barrels per day.

Natural gas represented 62% of total production, oil 21%, and NGLs 16%. Starting the second quarter financial performance, we generated approximately $171 million in revenues for the quarter and adjusted EBITDAX of $115 million, representing adjusted EBITDAX margins of approximately $3.62 per Mcfe, or roughly double that of our Appalachian peer group average. NYMEX natural gas prices during the period averaged $2.89 per MMBtu. We realized $2.34 per Mcf on natural gas sales, benefiting from our premium market access and transportation portfolio, including sales through the REX Zone 3 market.

Our oil price realizations for the period were $85.41 per barrel, with oil differentials of approximately $7.10 per barrel. NGL realizations increased 70% year-over-year to $32.27 per barrel, reflecting a more favorable production composition and stronger NGL pricing, which supported margins during the quarter. On costs, our controllable cash operating costs were down approximately 9% from the second quarter of 2025 and slightly down sequentially from the first quarter of 2026, excluding firm transportation costs.

During this quarter, controllable cash costs totaled $1.58 per Mcfe, comprised of $0.32 per Mcfe of LOE, $0.93 per Mcfe of GP&T, $0.20 per Mcfe of recurring cash G&A, $0.07 per Mcfe of midstream operations and maintenance expenses, and $0.06 per Mcfe of production taxes. Let me take a minute to discuss our GP&T specifically. Our reported GP&T expense increased during the quarter, primarily due to the inclusion of firm transportation costs related to the REX Zone 3 contract that we assumed in the Antero acquisition, as well as the increase in overall volumes. Excluding firm transportation costs, GP&T expense was $0.69 per Mcfe in the second quarter, reflecting a decline in operating costs quarter-over-quarter.

The other factor that contributed to our costs was an increase in liquids-weighted development. As our production mix shifted toward liquids, we earned more revenue per unit. But liquids require more processing and fractionation than dry gas. So a modest piece of the increase reflects real incremental costs that comes with a more valuable production mix and margin uplift. Looking at our full controllable cost stack, including LOE, GP&T, cash G&A, and production taxes, we expect this to decline structurally as volumes grow across our platform and the company increases its development of both the acquired Antero properties and our dry gas assets in Pennsylvania, with those volumes flowing through our own midstream system. During the second quarter, capital expenditures incurred were approximately $137 million, which included $129 million on development activities and $8 million on land activities. Our strategy is to build an integrated Appalachian platform that increases in value over time.

Rather than viewing each acquisition as a standalone transaction, we view each investment as another building block that strengthens the overall platform. Additional inventory extends development opportunities, producing assets increase scale, and midstream infrastructure lowers costs, while creating new commercial opportunities. Together, these assets improve capital efficiency, strengthen our cash-generating capability, and create long-term value for our shareholders.

Our capital allocation philosophy is straightforward. Capital follows returns, not commodities. We continue to invest in organic leasing and acquisitions, upstream development, and midstream infrastructure, while maintaining the flexibility to allocate capital to the highest-return opportunities as market conditions evolve. The 6- to 7-month development cycle time provides the operational flexibility to adjust activity, optimize development sequencing, and enhance returns as conditions change. Our hedging philosophy begins at the project level.

We evaluate the expected economics of each pad and use hedges to lock in those returns and provide greater visibility into our cash flows. For the remainder of 2026, we are 81% hedged on natural gas and 78% hedged on our total volumes based upon the midpoint of our guidance. This approach allows us to remain disciplined regardless of the commodity environment. Every investment is evaluated against our return thresholds and its ability to strengthen the platform. As the platform continues to scale, we expect higher infrastructure utilization, lower unit costs, and strong margins to further enhance our long-term cash-generating capability.

Finally, on guidance. For the full year 2026, we are reaffirming our prior guidance and continue to expect net production to average between 345 and 375 million cubic feet equivalent per day, representing growth of approximately 70% year-over-year. Similarly, our expectations for development capital expenditures, which are a combination of drilling and completions and midstream expenditures, remain in the range of $450 million and $500 million.

To wrap up, the second quarter reinforced the strength of our integrated Appalachian platform with a company record for adjusted EBITDAX and best-in-basin adjusted EBITDAX margins. The recent changes to our leadership only strengthen our capabilities as we continue to execute on our strategy focused on production growth and disciplined capital allocation. Operator, please open the line for questions.

[Operator Instructions] Your first question comes from the line of Timothy Rezvan with KeyBanc Capital Markets.

I want to start, Zack, on Slide 11. We appreciate the table you all provide with TIL timing across the asset base. We can see there's a clear oilier skew to summer and fall TILs, and then some gassier TILs in the fourth quarter. So I know you made the pivot to oil this year. Is the timing of this sort of intentional to capture the seasonality of gas prices? And how are you and the Board thinking about this as we go to '27 with the timing of oil and gas TILs?

Great question, Tim. Thank you. I think starting and speaking most clearly, we're trying to not be a company that chases the whims of a commodity price. So we've given Slide 11 because I think it really helps analysts model what's coming online when. And I'm glad that you appreciate that slide. I think what we see is when we have a strip that we like and we decide to execute a project, we can execute on hedges to de-risk that. So I think about it less of trying to time a gas turn-in-line with optionality and more of this is a function of our typical rig cadence matched with thoughtful hedging and the little bit of the reorganization of completions we did in the middle of the year to bring the oil fracs ahead of the gas fracs. So I think the timing should shape up well, but it isn't us trying to seek, you know, a proper time to turn a gas well on because of a theoretical gas price.

Okay, that's fair. And as my follow-up, I wanted to try to respectfully ask about the executive changes that were announced last night. I know you're limited in what you can say, but can you maybe give the Board's perspective about the specific skills that the new hires are going to bring and why you think that makes Infinity better kind of having them on board? Thank you.

Sure. So first of all, I want to thank David for all of his hard work, his dedication, and his friendship over the last 10 years. This is the right hire for us at the right time for this company. Cary has decades of public company experience to help with our growth trajectory. And we're very excited about that skill set that he brings to Infinity. And when we combine that with Andrew's capabilities, we think, along with the Board, that we are incredibly well-positioned for the scale growth that we are seeking.

Your next question comes from the line of Michael Scialla with Stephens.

Zack, you gave us some capital efficiency numbers year-over-year. I wanted to see more specifically if you had anything on the new wells that you've now completed on the acquisition properties, if anything you can say relative to how you're completing those wells cost-wise relative to the prior operator, and have you seen enough well performance there to say anything about the productivity of those wells?

Sure. I'll start by saying every day we spend with this asset, we're more and more excited about it. And also, it's still early days in our development philosophy on the asset. So everything that we're seeing is very new and fresh. We'll communicate more details about some of these synergies and efficiencies that we see in the coming quarters, but I can start by saying the well performance from the first 3 wells that came online this quarter is, we're very, very happy with them. They're meeting or exceeding our expectations, and our underwriting cases are developing with a rig, and moving the rig around the field has been quite smooth and quite efficient. Really proud of the team where we landed on our first pad with the drilling rig. Very shortly after close, drilled those 3 wells and have moved it to another pad. So this is, we're starting to see the full benefits of us having 1 rig in 1 field, moving it around.

And you have to give a shout-out to the land team who took an asset that was not necessarily prepared for full-field development like we are now, and continuing to give us wells to develop in the order in which we need them for the rig. So really happy with everybody's execution there. I think we are seeing a difference in our completion philosophy. We're pumping about 1,000 pounds of sand more than Antero had per foot, about 1,000 pounds of sand per foot more than Antero. And I think that's going to yield over time fantastic results. And I think we've got some benefits that we're going to be able to bring on some of the top-hole sections of drilling that if we give our drilling team a couple of more quarters, we're really going to be able to see some days come off of the underwritten drilling case too.

That sounds good. And it sounds like you're going to update your, I think you had a synergy target there -- annual synergy target of $25 million. That's we're going to get an update on that down the road here?

Yes, I think it's too early to speak in a lot of detail, but I think first and foremost, there's a lot of synergies that come from the REX contract that we bought with the deal, helping us get our volumes from our legacy pads to a premium market. And then we have maybe just a little bit of a highlight that we'll share more details on in the coming quarters. But the pad that the drilling rig is sitting on now is going to be a combination of 2 pads from the old drilling plan, the Antero drilling plan. So that's allowed us to eliminate pad construction, road construction, and pipeline construction, and put these wells that we're drilling onto an existing pad and lever what's already been built there. So really excited about that, and not going to talk numbers today, but you do that a few times and you really work through that $25 million in synergies quickly.

Sounds good. I wanted to ask on the, you mentioned on NGLs you're seeing an uplift there. I think you were at one point looking at potentially renegotiating your MPLX contract. Anything you can say there?

No, nothing I can say right now about that other than to just say we've got the contracts in place that are necessary for us to move our volumes. And as contracts need renewed, we'll negotiate on those. And we have a longstanding relationship with MPLX and excited to work with them as we move our volumes.

Your next question comes from the line of Paul Diamond with Citi.

You talked about recent improvements in the frac design. I guess in the near term, what do you see kind of the next opportunity beyond the recent tweaks? Is it in lateral length? Is it in proppant loading? I guess where is the next kind of step change you see in the near term?

Thanks for the question, Paul. I think first and foremost, we were excited about applying the completion design that we sort of mastered in Carroll County down in Guernsey and Northwestern Noble in the volatile oil window. We think that allows us to put more sand per foot with a little bit fewer stage count per well, which allows us to be maximized on our efficiencies and pumping hours per day, which is really what we measure on. Looking at stages per day doesn't necessarily compare you apples-to-apples. But when we can focus on hours pumped per day, that really lets us measure our efficiency.

So I think always completions is a spot where we focus on seeking efficiencies, and we'll continue to do that. I think we also see opportunities on the drilling side where we continue to optimize bottom-hole assemblies and really maximizing the amount of footage we can drill in a day to help us cut a day or 2 off of pro forma drilling, which makes a big difference in each project and lets us do more within a calendar year.

Got it. Understood. And then just talking about the -- we've seen some -- you guys talked about some ramp-up in the midstream utilization, but also some opportunities around potential third-party utilizations. I guess, can you give any detail on a potential timeline or kind of opportunity set you see there for ramping the third-party side of that equation?

Yes, no, thank you for that question. And I want to say that today and for the near future, our midstream revenues from third parties are going to be small. And I think for us, we're focused on utilizing that midstream system for our upstream development in the near term. It lets us have very low breakevens, very low operating costs and LOE. So we love the midstream system for our own operated assets. The third-party revenues are going to show up first in third-party interest inside the units we develop. And near term, because of the way our land team is putting together high working interest units, we really don't see those manifest in the near-term development of the Antero assets. Those are effectively 100% working interest units.

So they don't really generate a lot midstream revenue. We do think that there's opportunities, there's interest from third parties, and we'll continue to explore that. But for now, I think let's focus on using the midstream for our own gathering and our own cost controls, and we'll let the third-party revenues show up when they're there.

Got it. So more in-house in the near term, the potential opportunity downstream. Understood..

Your next question comes from the line of Sebastian Almodovar with Raymond James.

My first question has to do with your production guidance. You guys just reiterated annual production guidance, which implies a continued steep production ramp-up in the second half of '26. Can you speak to what exit rate production and oil volumes are embedded in that production guidance?

I think giving any guidance on exit rates probably isn't going to be helpful for me at this point. But I'll just steer you back to the guidance that we gave. Feel very good about our plan to execute on that. You're right that we've got some more ramp coming this year. And we're really excited about where each of these projects stand in their development cycle. So we're confident in the timing of those projects, and that's why we've been able to reaffirm our guidance. And as we work through the rest of the year, we'll continue to update folks on where we anticipate those volumes going at the back of this year.

That makes sense. And then as a follow-up, aside from diesel-related expenses, what is your view on potential service cost inflation during the second half of '26?

No, great question. And we see upward pressure on diesel, on steel, and a few other inputs into our business. But I'll give our operations team credit that when they can have efficiency improvements like they've had in Q2, they really help us offset that. So when we were reevaluating guidance, still feel very confident in our development CapEx that we gave and think that we're going to be able to execute inside of that range, even with some modest upside pressure on pricing.

Your next question comes from the line of John Annis with Texas Capital.

For my first one, I wanted to touch on the midstream strategy. Maybe a two-part question here. As production grows, do you expect to need to contract long-haul FT? And then more broadly, how do you weigh securing out-of-basin pricing against retaining in-basin exposure if regional demand sinks develop as expected?

No, great question. And I think one of the big assets we got in the Antero deal was the REX FT contract. We like it because it has sufficient volumes and sufficient duration to kind of bridge that gap that you're talking about, where we've got the ability to move our forecasted volumes out of Ohio while we wait for in-basin sinks to really begin to materialize. And in the meantime, we are active hedgers of both basis and hub. So we don't see us as having issues even with our in-basin sales. But for us, we've always approached FT as ensuring it to be an asset. And we're really excited about that REX contract because we think it gives us that flow protection that we seek while giving us also premium pricing and allows us to make sure our development can continue to move.

I appreciate that color. Maybe for my follow-up, following the Ohio acquisition, how are you thinking about the ground game from here? And is there an optimal inventory runway you would like to maintain across the portfolio?

I think we tend to speak in 10 to 12 years of inventory depending on drilling pace, and we like to maintain that year-over-year, and we think a ground game is incredibly important. Some of the best land dollars we spend don't actually add sticks. They only add interest in sticks or lateral length to a stick. So, it's a variety of outcomes, but we believe that a strong ground game and our local presence and our headquarters in Morgantown and our team's experience in the basin, I think positions us well for that. And you combine that with small and moderate M&A that we think could be around the space and the basin here over the next 12 months, you can really be positioned to make sure that, that inventory length extends, not shortens, even as we develop at 30 to 40 wells a year.

[Operator Instructions] Your next question comes from the line of Nicholas Pope with ROTH Capital.

A little more kind of detail on the midstream assets. Curious, as we look at this, the progression of cost, we've seen, I think the gathering and transport line item kind of move up with that big acquisition. And curious as we look forward, the benefits as you begin to utilize more of that asset, I know you all kind of increased the past few quarters. Yes, I think it was 25% to 35% utilization last 2 quarters, is that where we're going to see the benefit show up of this asset or is it going to be partially in realized pricing? Just curious at where we're going to see and where we should track the performance of that midstream business as you tie it more into assets, get it more utilized going forward over the next year.

No, great question. I think you're going to see it show up in a few different ways. I think, first of all, the step-up you saw in GP&T with the acquisition of the asset was really that REX Zone 3 contract. So we spent some time talking about that in our materials this quarter to help people understand how that really is a contract that gives us higher realizations. And we don't necessarily think about that as really an operating cost of our midstream business, but we've shown it both ways so people can understand that. This quarter, our GP&T costs also had upward pressure because of the liquids weighting.

I think it's important to know that when we bring on these legacy volatile oil wells, they're coming on in a higher-cost environment in which we don't own the midstream. So we pay gathering, we pay fractionation, transportation, all those things for those gas volumes. And when the wells come on and outperform our expectations like these wells have done, that's more gas molecules that are getting hit with those fees.

So all good problems to have. But I think your question on how do we see this midstream asset really manifest in value to the company, I think you'll really begin to see as more and more volumes come on. We have these low gas expenses hitting some large gas volumes over the next couple of quarters that will help us bring down our collective GP&T on a per-unit basis, so you'll see it there. I think, like I said to a previous answer, I think the third-party revenues on that midstream are great. Nice to have options in the future, but that's not a measurement of success of owning this midstream. For us, it's about making sure we've got best-in-class breakevens. We have the ability to be thoughtful with when we drill wells and put them into a very low-cost system so that we can make sure we've got the best project returns for our shareholders.

Your next question comes from the line of Michael Scialla with Stephens.

Yes, I just wanted to follow up on the deep Utica. I know you said you had drilled a 9,500-foot lateral and taken a core. I just want to see if there's any more detail you could provide there, how the core may have looked relative to expectations and any update on timing. I think you previously had anticipated that well would be on sometime toward the end of the year. I want to see if there's any update there.

Sure. So I think, thank you for that question. We're excited to talk about the deep dry gas Utica, but I think the punchline here is the story is there is no story. The team executed on the drilling and the science phase flawlessly. Very excited to have captured the core across the entire producing interval. It doesn't -- core doesn't get evaluated in days or even weeks. It's going to take a long time for them to get through all of their analysis. So for now, we're focused on completing the Marcellus wells on that pad. We drilled 3 Marcellus wells in addition to the Utica well. So we'll use the time while we're completing those wells to finish evaluating, to the extent we can, the core and the logs from the Utica, and then we'll decide if we want to complete the well now or complete it later. But we're happy with the execution that the drilling team gave us on putting that well in the ground.

We have reached the end of the Q&A session. I will now turn the call back to Zack Arnold for closing remarks.

All right, well, thank you all very much for your time and interest in INR today. We look forward to connecting again next quarter. Thank you and have a great day.

This concludes today's call. Thank you for attending. You may now disconnect.

Hello, everyone. Thank you for joining us, and welcome to Infinity Natural Resources First Quarter 2026 Earnings Call. [Operator Instructions] I will now hand the call over to Mr. Tom Marchetti, Vice President of Investor Relations. Please go ahead, sir.

Thank you, operator. Good morning, and thank you for joining the Infinity Natural Resources First Quarter 2026 Earnings Conference Call. With me today are Zack Arnold, our President and Chief Executive Officer; and David Sproule, our Executive Vice President and Chief Financial Officer. In a moment, Zack and David will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations section of our website, and we may reference certain slides during today's discussion.

A replay of today's call will be available on our website beginning this evening. Before we begin, I would like to remind everyone that today's call may contain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied.

All statements that are non-historical facts are forward-looking statements. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those forward-looking statements. Please review our earnings release and risk factors discussed in our SEC filings.

We will also be referring to certain non-GAAP financial measures. Please reference our earnings release and investor presentation for important disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Zack.

Thank you, Tom, and good morning. We appreciate everyone joining us today to review Infinity Natural Resources first quarter results. The first quarter was pivotal for Infinity. We successfully closed the Antero, Ohio Utica acquisition in late February, our largest transaction to date and added working interest in our Pennsylvania asset sets through the Chase acquisition. These acquisitions immediately increase our scale with our operated well count increasing from 154 to 395 and our midstream system expanding to over 250 miles of gathering and water pipelines, positioning Infinity for disciplined growth through the end of the decade.

Importantly, we did so while preserving the quality of our balance sheet through strategic financing, including the issuance of perpetual preferred securities and senior notes. Since closing these transactions, our teams have been focused on integrating the assets into our operational platform. This includes onboarding personnel, evaluating the new inventory and identifying opportunities to optimize operations across the acreage and associated infrastructure.

The more time we spend with the Antero assets, the more excited we become about the opportunity, especially at the midstream infrastructure, which we will discuss in more detail in a few minutes. Before that, let me review production and operating highlights from the first quarter.

Net production averaged 299 million cubic feet equivalent of gas per day, a year-over-year growth rate of 88%. We turned to sales 4 wells in the volatile oil window with 53,000 lateral feet. 2 in early February and 2 in mid-March. On the operating front, we added a second frac crew and a second rig during the quarter, and we stimulated 11 wells and drilled 10 wells to TD, which is a company record. One of the frac crews was deployed to the assets we acquired from Antero approximately 30 days after closing near the end of 1Q and we expect to turn these first 3 wells from the acquisition to sales during the second quarter.

We've had 1 rig on legacy Infinity volatile oil window assets and 1 rig on legacy Infinity natural gas assets since January, and we intend to move a rig on to the newly acquired Antero assets later this quarter. As we have previously discussed, our plan for the balance of 2026 is to run 1 dedicated rig on legacy Infinity assets, drilling both volatile oil and dry gas wells and 1 rig on the newly acquired assets.

As of today, we have accelerated completion activity in our volatile oil window to capture stronger near-term returns, which includes pulling 4 oil-weighted wells into the second quarter from later in the year with mostly unhedged barrels. That said, we retain the flexibility as always, to quickly pivot between commodities and we'll lean harder into the natural gas market if conditions warrant the shift.

We continue to focus on longer laterals. During the first quarter, the average lateral length turned in line was over 13,000 lateral feet. We benefit from efficient cycle times with multi-well projects continuing to reach first production within 6 to 7 months, supporting faster capital recycling and improved returns.

As an example, we started drilling on 4 well 55,000 lateral foot oil-weighted pad in November, and we expect to turn in those wells in the coming days. Coming back to our newly acquired midstream infrastructure. In our minds, the scale and versatility of this unique system is vastly underappreciated with 140 miles of gathering lines, 90 miles of water lines, 6 compressor stations, 43 compressors and nearly 80,000 horsepower.

This is a turnkey system with no lead time or bottlenecks that would likely take years to replicate. We have retained nearly all the field employees associated with these assets and hired additional senior leadership for Midstream, including a VP at Midstream.

The continuity and deep expertise of our Midstream bench is truly invaluable. We are excited by the value that we can unlock from the system. To put it bluntly, we believe it is poised to become a meaningful contributor to future results as we are 1 of the limited number of operators in the Appalachian Basin with owned Midstream infrastructure. Currently, the system is underutilized, operating at less than 1/4 of its currently available capacity providing significant runway to support not only our own development but also third-party volumes. We received third-party volumes on the system for the first time during the first quarter, and we will be focused on increasing third-party volumes on the system.

As we move through the year, we expect to drive a meaningful ramp in throughput that will contribute to our financial results. This infrastructure also provides a significant structural cost advantage as we leverage existing pads and pipeline connections, significantly reducing or eliminating the need for incremental Midstream capital on new development. As of today, approximately 75% of Infinity's natural gas volumes are flowing through our owned Midstream system, and we expect that to increase as we ramp development.

This system creates a strategic advantage for us that we expect to drive improved margins and lower breakevens over time. We'll share more over time as we continue to operate the asset sets. I will now spend a few minutes on the macro. We remain constructive on the longer-term outlook for both liquids and natural gas. Oil and liquids markets in Appalachia remained strong with a combination of domestic and international demand from refining and chemicals driving a favorable pricing environment.

Beginning in April, we have increased our take-in-kind NGL volumes which provides us greater control and optimization of the realized pricing specific to propane, butane and pentane. For natural gas, we see a clear cadence of demand growth with near-term strength driven by LNG exports, continued momentum from gas-fired power generation, in-basin data centers and longer-term expansion tied to industrial development. As these demand drivers scale, we expect regional gas differentials to tighten alongside broader market growth. Given our outlook for oil and liquids, we have leveraged the flexibility of our platform to adjust our completion schedule and accelerate facilities construction to pull forward oil-weighted wells into 2Q and to capture stronger price realizations.

We will continue to evaluate our development plans across the portfolio with a focus on directing capital towards the highest return projects. Against this backdrop, here's where our plan stands for the second quarter. As I touched on earlier, we expect to turn in line a 4-well pad in the volatile oil window in the coming days, representing 55,000 lateral feet. We also expect to bring to market our first barrels from the Antero acquisition later this quarter, a 3-well pad in our rich gas area with 53,000 lateral feet.

That's a total of 7 wells turned in line and 109,000 lateral feet during the second quarter. With that, I will turn the call over to David to review our financial results and outlook.

Thank you, Zack, and good [indiscernible]. Our financial and operational results for the first quarter reflect continued execution by our team. We anticipate that our production will increase each quarter throughout the remainder of the year. During the first quarter, our net production averaged 299 MMcfe per day. We expect the first quarter to be our lowest production total for the calendar year.

In terms of the components of production, oil production totaled approximately 9,600 barrels per day for the quarter, up 16% year-over-year. Natural gas production averaged 195 MMcfe per day, up 169% year-over-year.

And NGL production increased 25% year-over-year to 7,800 barrels per day. Natural gas represented 65% of our total production, with oil being 19% and NGLs being 16%. Turning to financial performance. We generated approximately $155 million in revenues for the quarter. and adjusted EBITDA of $97 million, representing adjusted EBITDA margins of approximately $3.61 per Mcfe, which we believe is best-in-class in the Appalachian Basin. The company saw improved natural gas prices during the period that averaged $4.86 per MMBtu.

Our regional differentials remained steady at $0.69 per MMBtu, reflecting a greater weighting towards a lower Btu per content in our gas stream. Oil price realizations for the period were $65.77 per barrel. First quarter oil differentials tightened to slightly less than $7 per barrel during the period. We anticipate our oil differentials to remain consistent, around $7 to $8 per barrel for the second quarter. NGL realizations were strong during the quarter, supported by better NGL composition, firm pricing and export-driven demand, contributing to the overall strength of our revenues and reinforcing the value of liquids-weighted development across our portfolio.

Turning to costs. Our controllable cash operating costs during the quarter totaled $1.43 per Mcfe. These costs reflected the impact of an extremely cold winter, which drove higher rental costs and snow removal as well as true-ups for annual compensation. On a year-over-year basis, controllable cash operating costs declined approximately 18%, a reflection of the benefits of scale and improved operating leverage. As volumes grow across our Appalachian platform, and we increase the utilization of our owned Midstream infrastructure.

We expect our overall cost structure to improve further. During the first quarter, capital expenditures incurred were approximately $123 million, which included $112 million on development activities and $11 million on land activities. Our capital allocation strategy remains disciplined and focused on long-term value creation. During the quarter, we deployed completion crews to prioritize development in our volatile oil window to capture the strength of near-term oil markets. Our stimulation activities are expected to shift back toward natural gas towards the back half of this year.

We continue to prioritize high return opportunities across our Utica and Marcellus assets, selectively expand our inventory through accretive acquisitions and organic leasing, and maintain a strong balance sheet with ample financial flexibility. During the quarter, we raised $550 million in senior notes, $350 million of preferred equity. The transactions enabled us to pay down all outstanding debt under our revolving credit facility and increase our liquidity position while expanding our investor base with institutional credit investors and premier energy investors in Quantum and Carnelian.

We are well positioned with financial flexibility to execute to our business plan. At quarter end, we had net debt of approximately $477 million and total liquidity of approximately $929 million. Our pro forma net leverage on an LTM basis was 1.3 turns during the period.

We would anticipate our net leverage ratio to decline during the course of the calendar year towards our target leverage level. For 2026, we continue to expect net production to average between 345 MMcfe and 375 MMcfe per day, representing growth of approximately 70% year-over-year, with gas production of approximately 235 MMcfe to 255 MMcfe per day and oil/liquids production of 18,000 to 20,000 barrels per day. Development capital expenditures, which are a combination of drilling and completions and Midstream capital expenditures are expected to range between $450 million and $500 million. With that, I will turn the call back to Zack for closing remarks.

Thank you, David. As we move through 2026, we are advancing development across our assets with a continued focus on consistent operational execution, strong financial returns and long-term shareholder value creation. Across the Ohio Utica and Pennsylvania, Marcellus and Utica, our portfolio offers a deep inventory of high-quality development opportunities supported by our owned midstream system. We are particularly excited about the opportunity within our Midstream platform where increasing volumes flowing through the system are not only driving incremental efficiencies and margin benefits but also positioning Midstream to become a more meaningful contributor to earnings and cash flow over time.

We will continue to evaluate complementary acquisitions that strengthen and expand our integrated Appalachian business while also assessing development timing and potential hedging opportunities to optimize returns in the current commodity price environment. Operator, please open the line for questions.

[Operator Instructions] Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Zack and team. Look, I mean, obviously, as your business strategy have been, you're very flexible to change your activity pace and cadence with the commodity and the macro and pulling forward some more oil stuff. Can you just give us a sense of what should we expect on some of the cadence on some of that oil production? Obviously, 1 or 2 wells can make a big difference from you all. But it seems like -- should we see a bigger step-up in oil?

And can you kind of talk about like how the base decline rate works right now with you all and what to expect in the next quarter or 2?

Great question, Scott. This is Zack. I'll take the first part of that, and David can kind of chime in, we'll tag team it. But I think, first and foremost, I'll address your decline question. And we continuously are pleased and proud of our PDP and our new well performance. I think we've had very nice results and we continue to demonstrate that. As we exited last year, we had a really big ramp into the end of the year. It was driven by a lot of turning lines in late Q3 and early Q4.

So that saw a big ramp there. And the wells that we talked about turning line in this quarter, they're really going to manifest more in second quarter production as they came in line late in the quarter and especially when you factor in effective contributing days at target rates. So I think you'll start to see the Q1 development really showing in Q2 as well as the Q2 wells beginning to come in line.

When we talked last time about what changes we wanted to make based on commodities, I think what we've really tried to do is not blow up the development schedule we've put in place, but look for ways to suddenly pull barrels forward. And we're really proud of what the team has done. We'll have some turning mines coming online in June, that weren't anticipated to be due. So that's meaningful as we bring those barrels in. That will put them at full rate in July ahead of when we had originally budgeted. And those -- because of that acceleration, that gives us a lot of exposure to unhedged barrels there. I'm sorry, if I missed anything else in your question, do you want to add back into.

Your next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

Scott sort of stole our first one on the oil. But I appreciate the outlook there. But I did notice you have a 10,000-foot Utica test being [indiscernible] this quarter. I know there's been some -- it seems like it may be underway soon or it's finally going to happen here. There's no completion schedule looks time line this year, I guess, maybe it's more of an early 2027 event. But can you talk kind of about your predrill expectations for this well? Do you view this like a development well? Is it more like a science well? Is there anything specific you're kind of looking to confirm here and just any idea on when you plan to turn it to sales would be helpful.

Yes. All good questions, Tim. And it's a question that we get quarter-to-quarter. I think what we can say right now is we continue to watch offset operations and are monitoring what our peers are doing. We do have a rig on that location, and it's going to be focused on the science portion of this project. We'll do some -- we'll drill a vertical pilot and collect some data there that we'll analyze. You are right in noticing that we don't intend to drill this well horizontally or completed in this calendar year. This is really step 1 of a valuation. So we'll go collect some science and spend some time of observing it and measuring the things that we need to, so we can properly plan our development there.

But as I think we've said before, it's an exciting well for everyone else included it, but it's 1 out of the 40-plus, plus we have this year. So we're really excited in focusing our capital predominantly on projects that have clearly defined returns and a long track record of success.

Okay. Great. We'll stay tuned, I guess, for updates on that. And just want to follow up. I know David gets this question every quarter, but just kind of big picture kind of M&A trends. We see the same thing you all see with leverage kind of going to or below 1 turn by the end of the year. And I know you're integrating Antero, but you're pretty clearly a growth-focused company. So just kind of curious what your capacity for incremental M&A, like larger pieces is at this point and what we're seeing in the market.

Yes. I think -- thanks for the question, Tim. This is Dave. I think for us, one of the things that we were very cognizant of is both integrating and positioning the company for continued opportunity sets. And so we are highly active in that environment. We are highly selective in that environment also. So we are very well positioned to capitalize on assets that we see that fit our portfolio. And so we will continue to evaluate those as they come to -- across our sort of desk, if you will, but we are very selective in that.

Obviously, we've integrated a very big asset here. That integration has gone extremely well and positions us to not just execute on our development plan that we have in front of us, but positions us to have the flexibility to evaluate other things as they come through.

Your next question comes from the line of Nicholas Pope with ROTH Capital.

I would like to talk a little bit more about the integration of the Antero assets. Obviously, they haven't seen a lot of drilling in the past few years before you guys acquired them. And just as you kind of -- I think we're 3 months -- almost 3 months into owning the asset, curious kind of as you look maybe at the existing producing base like maybe what the opportunity set looks like low-hanging fruit to kind of optimize production on that asset? And maybe how that might flow through LOE kind of in the near term as you kind of look at some of that opportunity set, if anything changes, maybe or kind of how you're looking at that asset as you kind of got in-house?

No, that's a great question. Thank you, [ Pasi. ] This is Zack. I'll take a first crack at it. I think, first and foremost, we are identifying some low-hanging fruit and things that our production engineering team can focus on. And it's kind of small ball stuff where you're working on bottom-hole assemblies and plunger lifts and some things that are just really optimizing the existing legacy production there, but still it's worth that you should do, and we're excited about that, and our team is focused on that.

When you think about LOE impacts, we're still completely getting our mind around the optimization of these wells that we can do. I think owning our midstream is, first and foremost, critical, but 1 spot where we see some exciting near-term activity to help that is with reusing of water with the increased completion activities on these assets and the -- and our legacy assets in Wolf Run gives us a better capability to reuse water from the field, and that should have a net positive impact there on some of our LOE.

And I guess maybe stepping back a little further, like the broader LOE for the company. How do you anticipate that kind of shape over the remainder of 2026 as you kind of look at these assets?

Sure. So I think when you look at the first quarter, our LOE ticked up to about $0.33 in Mcfe. I think that's more of a reflection of the very, very harsh winter that we had in this this part of the country. I think if you look at year-over-year, our costs have gone down significantly. We would anticipate those costs to continue to decline as they've had trend line wise and '25 I would continue to anticipate that to occur in 2026.

With regards to the Antero integration and the impact there in. As that kind of mentioned with our ownership of the Midstream assets, we start with a significant head start because our GP&T cost is raised with regards to our near gathering and compression charges are raised with regards to the development of those assets.

So you should anticipate over the course of this year, our overall cost structure to continue to decline, both from an impact from volumetric growth as well as from just the cost structure integration where the Antero assets have a lower cost structure than our assets in Carroll County or in legacy Guernsey County.

Your next question comes from the line of Michael Scialla with Stephens.

You were able to add some acreage during the quarter. I just want to see what the opportunity set looks like there? Is it any different now with the Antero acquisition? And maybe how the cost of land have changed over the past year. Can you give any sense there and however you want to break down in terms of cost per new drilling location and maybe difference between Ohio and Pennsylvania, if you could.

Yes, we've been really proud of what our team has done to continue to add acres, especially in a quarter that was overshadowed by closing of 2 deals. So them adding acres, I think, was a testament to their ability to execute 2 jobs at once. So very proud of that. We've seen nice opportunities to add acres both inside and outside of our units in both Ohio and in Pennsylvania to give them credit for being able to focus dollars effectively in areas that we're interested in.

I think with the new Antero acquisition, giving our land department more units to focus in has helped us be thoughtful with cost allocation and making sure that we're spending our dollars into acres that will get developed and a cost that we're happy with.

As a reminder, in Ohio, once you reach a threshold for statutory utilization, that puts you in a good position from a leasing perspective to execute on the development plan in front of you. So I like that opportunity. Might stay away from giving specific lease per acre numbers. But I will say our team is always focused on getting the best value that they can, understanding where acres fall into our inventory and focused on being very thoughtful with dedicating those dollars and really focused on leases that are tight cycle times for us, putting them in front of the drill bit, putting them in units that we plan to drill, so that we can get the return on those lease sellers very quickly.

Appreciate that, Zack. I know you guys had talked about potentially pivoting at some point to generate positive free cash flow, maybe your latest thoughts there on what the timing of that might look like?

I mean, I think in terms of our overall development program and the guidance that we provided, obviously, this is a fairly capital-intensive year as we've discussed sort of priming the pump with regards to the Antero acquisition that we've closed upon. But we would anticipate trending down over the next 5 years to be consistent with that of our offset peers while still having outsized growth. So we would anticipate our CapEx as a percent of EBITDA to be lower this year than last year. And we would anticipate that trend to continue into the coming years.

[Operator Instructions] Your next question comes from the line of Paul Diamond with Citi.

Just wanted a quick one to touch on. You guys talked about shifting activity more towards dry gas in the latter half of the year. I guess from a production perspective, how should we think about that cadence-wise? Is that a pretty midyear progression? Or would we still expect to see those kind of step change moves?

In terms of step changes of the production, Paul?

Yes, the more chunky moves in production up on oil, down on gas, that sort of thing.

Yes. I would expect that we will still exhibit heightened growth in every one of our hydrocarbons quarter -- each quarter going forward. I think the cadence of activity would lend itself to have a really heightened third quarter with regards to Turned-in-Line relative to the overall year. I do think that adding natural gas towards the middle to end of the year does have an impact on our overall natural gas volumes. But again, it's sort of relative to the other components and the time frame of it being on.

So I wouldn't necessarily expect it to be -- it's a question of what is the degree of step change, but we would anticipate each quarter to be higher than the last as you kind of shape the development of the assets that we have. So I'm probably not going to give you the exact answer you want there, but I would tell you that we would anticipate our fourth quarter to be our highest production quarter for the year.

Got it. Understood. And then just one quick more strategy question. So obviously, you guys have been growing at a pretty decent clip, both organically and in. Thinking about how you see that growth rate into '27 and beyond, is there kind of a point where you see it slowing usually leveling off? Or is it kind of a target rate where it's like, okay, where it get to that next level where [indiscernible] from a strategy perspective, where does -- how linear should we expect that growth to remain?

Yes. I think, look, a lot of small -- a lot of big numbers and small numbers of aspects is you can't continue to grow at a 70%, 80% kind of clip. For us, as we think about of 2027 and beyond. Obviously, we haven't provided guidance on that. I think it's fair to say that our production growth will still be relatively elevated compared to our peers, but we would start to expect to trend down as a percent of reinvestment rate over that time period.

Your next question comes from the line of Scott Hanold with RBC Capital Markets.

Sorry, I had myself on you before when I was have ask my question. But my follow-up was on the infrastructure and the infrastructure utilization. Obviously, you all talk about it, it's sort of being underutilized right now and an opportunity to kind of continue to grow that -- can you speak to like how much of the capacity do you think you'll reserve for third parties versus keeping on your -- for yourselves and your production growth? And what kind of third-party revenue growth could that generate here over the coming quarters?

Yes, I'll take the portion on -- the first part of that question and handle that. So I think first and foremost, when we look at these assets, we're incredibly impressed with how things have been positioned walking across some of these compressor stations and realizing just the infrastructure that's in place there and how little utilized it is today gives us a lot of excitement about ways that we can continue to grow the use of that system.

So I think when we think about third-party volumes and we think about our own volumes, we're always going to prioritize our own volumes first. I think as we begin to think about ways that third-party volumes materialize and most of those initially are going to materialize just through the units that we develop and having other operators inside of our units and other interests that we don't have lease inside of units that -- as you see that, that will come naturally with our own development profile. So I think we won't put ourselves in a position in which the infrastructure is bottlenecked because of other competing objectives that we have.

And I think our ability to lever the expertise of some of the field staff we brought in as well as some of the senior leadership that we're adding to the team really allow us to look closely from an engineering and a business perspective here, making sure that the system that we have today continues to be optimized for however we add volumes to it through our own drill bit or third-party volumes.

Yes. I would just add, Scott, that it's 600 million a day pipe. We're actively developing in that area, as Zack's highlighting but we are highly incentivized to fill that pipe. And so we will push to do so.

Okay. When you send up these contracts with these third parties, are they more like spot kind of month-to-month kind of volumes? Or do you -- are you locking in some longer-term contracts with them?

Yes. I think at this stage, we'll probably stay a little bit muted on that. I think for -- it's a case-by-case basis on a lot of the opportunity sets that we see. But we'll probably talk a little bit more about that tool during the course of the year as we ramp up things. And as you think about modeling, right now, it's really small numbers. So it's not that impactful. It's truly just opportunities that we're making sure that we're thoughtful with exploiting.

There are no further questions at this time. I will now turn the call back over to Zack for closing remarks. Please go ahead.

Thank you very much for joining us for the call today. We appreciate your continued interest in the company, and we look forward to sharing additional results with you soon. Operator, back to you.

Thank you. This concludes today's call. Thank you for attending. You may now disconnect.

Hello, and thank you for standing by. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the Infinity Natural Resources Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]

I would now like to turn the conference over to Tom Marchetti, Vice President of Investor Relations. Please go ahead.

Thank you, operator. Good morning, and thank you for joining Infinity Natural Resources Fourth Quarter and Full Year 2025 Earnings Conference Call.

With me today are Zack Arnold, our President and Chief Executive Officer; and Dave Sproule, our Executive Vice President and Chief Financial Officer.

In a moment, Zack and David will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations section of our website, and we may reference certain slides during today's discussion.

A replay of today's call will be available on our website beginning this evening.

Before we begin, I would like to remind everybody that today's call may contain certain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied. All statements that are not historical facts are forward-looking statements. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those forward-looking statements.

Please review our earnings release and the risk factors discussed in our SEC filings. We will also be referring to certain non-GAAP financial measures. Please refer to our earnings release and investor presentation for important disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures.

With that, I will turn the call over to Zach.

Thank you, Tom, and good morning, everyone. Before I begin, I'd like to formally welcome Tom Marchetti to our team. Tom will lead our Investor Relations function and is a great addition to the team. We appreciate everyone joining us today to review Infinity National Resources Fourth Quarter and Full Year 2025 results and to discuss our outlook for 2026.

Overall, 2025 was another transformational year for Infinity. Importantly, we did what we said we do during the IPO process. We continue to add scale. We've significantly increased production, we've grown our operating cash flow. We've expanded our asset base through acquisitions, we've access to capital markets, we've entered into strategic partnerships, and we preserved our operational and financial flexibility. We've been busy. Most importantly, our Appalachian platform continues to deliver strong operational and financial execution across both our extensive Utica position in Ohio and Marcellus position in Pennsylvania.

Our results during the fourth quarter and year overall are underpinned by our strong well performance across our asset base as well as the disciplined execution of our development program. Our teams remain focused on improving drilling and completion efficiencies, extending lateral lengths and maintaining capital discipline as we developed our high-quality asset base.

Before reviewing our operational activity for the quarter it is worth highlighting the strength and flexibility of our development portfolio across Appalachia. We have over 390 locations across our portfolio, representing more than 10 years of inventory when developed on a 2-rig program. Our returns in oil and liquids weighted projects are strong, especially true in today's oil environment, and our gas returns are strong as well. Balance, optionality, it is how we build our business in order to maximize value for our shareholders. Well costs are consistent across our position, whether in our Ohio Utica development or our dry gas Marcellus wells, which allows us to allocate capital efficiently across our development opportunities depending on commodity conditions.

In addition, much of our drilling and completion design is standardized across our development program utilizing common equipment and consumables packages that allow us to efficiently shift activity between Ohio and Pennsylvania. Combined with our extensive drilling inventory across these development areas, this portfolio provides significant operational, commodity and financial flexibility as we allocate capital across our assets. As a result, our development program can be adjusted to prioritize the highest return opportunities while maintaining disciplined growth.

During the fourth quarter, we continued to operate 1 drilling rig across our base assets. We added a second rig in January, bringing our total operated rig count to 2, advancing development across our diversified portfolio. During the fourth quarter, net production averaged 45.3 MBOE per day, bringing full year production to 35.3 BOE per day. exceeding the high end of our guidance range for fiscal year 2025. When compared to 2024, the company was able to deliver year-over-year growth of approximately 46%.

During the fourth quarter, we spudded 9 wells, totaling approximately 142,000 lateral feet, while finishing completions activities and turning into sales 6 wells totaling 103,000 lateral feet, evenly split between Ohio Oil water project and Pennsylvania dry gas projects. For the full year, we turned 23 wells into sales, including 12 wells in Pennsylvania and 11 wells in Ohio reflecting our balanced development approach across our asset base.

Our development program continues to emphasize extended lateral development and operational efficiencies that support strong capital returns across both our Utica and Marcellus positions. For calendar year 2025, our average well turned into sales exceeded 1,700 lateral feet. The longer laterals help to reduce our per foot drilling costs, it's not just about drilling longer laterals. It's also about cycle times, getting those wells online and having them track our anticipated well performance.

We continue to target 6 to 7 month cycle times on our development projects ranging from 3 to 5 wells, which we believe is one of the fastest cycle times in the industry. With regards to well performance, we placed a lot of wells online in the second half of 2025 and we are pleased with the performance of those wells to date, and they continue to track in line with our type curve expectations across both development areas.

Looking forward, we intend to operate 2 rigs throughout calendar year 2026. While the world is ever changing these days, especially with commodities, we anticipate allocating slightly more capital towards natural gas-weighted development based upon wells turned into sales during the year. Approximately 30% of our projected wells turn into sales will be on the assets we recently acquired, developing our rich gas locations in the Utica Shale of Eastern Ohio. Turning to our recent acquisitions.

On February 23, we closed the previously announced $1.2 billion acquisition of Ohio Utica assets from Antero Resources and Antero Midstream. This transaction is a highly complementary bolt-on to our existing position in Ohio, adding extensive inventory across multiple phase windows directly adjacent to our legacy acreage further supporting our long lateral development strategy.

Just as importantly, the transactions included ownership in the associated midstream system, which provides us with attractive midstream costs and further reduces well breakevens across the acquired assets. We intend to devote a rig to the development of these assets during the year, beginning early in the second quarter, and we expect our first path from the acquired position to come online during the second quarter.

As we began developing this inventory, we expect to increase production from these assets meaningfully in the coming months and years. Not to be forgotten with all of our activities, we also completed the Chase acquisition which increased our working interest in our dry gas South Bend field in Pennsylvania. Transactions like this where we can increase working interest in assets we already operate are typically among the most attractive investments that we can make using our equity as they increase our exposure to future development and production without requiring incremental corporate overhead for G&A. This acquisition represents another milestone for Infinity as it is the first time post IPO, but we have used our equity to acquire assets.

Together, these transactions expand our development inventory, increase our participation in high-quality drilling projects and strengthen the strategic position of our Appalachian platform through enhanced infrastructure and marketing assets.

In conjunction with the Antero transaction, Infinity successfully issued $350 million of perpetual convertible preferred stock to 2 highly respected energy investors, Quantum Capital Group and Carnelian Energy Capital. We believe the strong demand from these investors reflects confidence in both in the quality of the underlying assets and our long-term development strategy. This hybrid equity structure is consistent with our philosophy of maintaining a strong and flexible balance sheet. We were able to raise significant equity capital above our IPO price while reducing outstanding debt and preserving financial and strategic optionality for the company.

Importantly, this capital supported our election to increase our participation in the Ohio Utica acquisition to a 60% working interest, deepening our ownership in an asset we know well and believe strongly in, while maintaining balance sheet discipline as we continue to advance development across our Appalachian platforms.

Looking more broadly at the market environment, we continue to see strong structural demand for natural gas and associated liquids across North America. Recent geopolitical developments in the Middle East have strengthened crude prices across the forward curve through 2030, representing another opportunity for us to demonstrate the value and flexibility of our unique asset base. With our development activities in the fourth quarter, we have significant oil-weighted volumes planned for the first half of 2025.

We have taken this opportunity in the commodity markets to lock in attractive oil hedges for 2026 and 2027 using a balance of swaps and colors. PAUSE Additionally, we are evaluating our development plan as to whether we should accelerate any additional oil projects to take advantage of attractive prices. We cannot predict whether this will be a short-term event but we will continue to monitor the situation to see if elevated oil prices prove to be longer lasting and warrant additional development of our oil inventory.

On a more micro level and for our Ohio Utica liquids production specifically, we are witnessing increased regional demand dynamics, condensate and other light hydrocarbons produced from liquids-rich plays, such as the Utica are used both as refinery feedstock and as diluent for heavier crude oil as production of heavier barrels from regions such as Canada and Venezuela increases, producers require additional volumes of condensate and other light hydrocarbons to blend those barrels to move them through pipeline systems and into refineries.

Given our proximity to regional refining markets and infrastructure, we believe our Ohio Utica liquids production is well positioned to serve this demand.

Turning to natural gas. Global demand for U.S. LNG continues to expand and with additional liquefaction capacity expected to come online over the next several years, U.S. natural gas supply is increasingly positioned to serve global energy markets. Domestically, rising electricity demand is expected to drive additional natural gas consumption within the U.S. power sector.

Looking ahead, we remain focused on executing a disciplined development program the balances growth with capital efficiency. Our diversified asset base across our Appalachian platform provides flexibility to allocate capital towards the highest return opportunities depending on market conditions. With that, I will turn the call over to David to review our financial results and outlook.

Thank you, Zach, and good morning. Our financial results for the fourth quarter and full year reflect the strong operational execution delivered by our team throughout 2025. During the fourth quarter, net production averaged 45.3 MBoe per day, and we generated adjusted EBITDAX of $94.0 million representing adjusted EBITDA margin of approximately $3.76 per Mcfe or $22.58 per BOE.

During the quarter, we realized average prices of $51.22 per barrel for oil, $3.14 per Mcfe for natural gas and $23.56 per barrel for natural gas liquids, with realized pricing reflecting regional market conditions and differentials across Appalachia, consistent with our expectations during the quarter.

For the full year, adjusted EBITDA totaled $261 million, reflecting continued production growth, combined with disciplined cost management. Operating costs during the quarter averaged $5.56 per BOE, reflecting continued operational efficiencies and increasing contribution of natural gas production from Pennsylvania within our overall portfolio. We believe that we maintain one of the lowest operating cost structures in Appalachia, supporting our strong capital efficiency metric. We continue to witness our cost decline approximately 36% during the fourth quarter when compared to the prior year.

As we continue to expand our natural gas volumes in Pennsylvania, we would anticipate to experience further decline in our overall cost structure as those volumes are on our wholly owned midstream system. During the fiscal year 2025, we incurred approximately $326 million in capital expenditures, including drilling and completion CapEx of $274.7 million, land spend of $35.5 million and midstream and infrastructure investments of approximately $16.1 million.

For the full year, development capital expenditures totaled approximately $290.8 million, consistent with our previously communicated development plan. Our capital allocation framework remains focused on maximizing long-term shareholder value. We prioritized funding high-return development opportunities across our Utica and Marcellus assets, expanding our development inventory through targeted acquisitions and maintaining a strong and flexible balance sheet.

Additionally, during the fourth quarter, we repurchased approximately 87,000 shares of Infinity common stock at an average price of $13.50 per share for our total repurchases of approximately $1.2 million during the quarter. We remain opportunistic in executing share repurchases while ensuring that capital returns do not impact our ability to execute. Our development program will pursue strategic opportunities.

As Zack mentioned previously, during the fourth quarter, we also completed a $350 million strategic equity investment in the form of a perpetual convertible preferred securities, which is convertible into common equity at $21.36 per share, which is above our IPO project aligning investors with long-term equity value creation. This hybrid structure provides a permanent equity capital that allowed us to repay a portion of the revolver borrowings used to finance through Ohio acquisition, while also supporting the increase in our working interest of the transaction to 60%.

Importantly, we structure limits immediate solution to existing shareholders and preserves balance sheet flexibility relative to incremental debt. At year-end, we had net debt of approximately $148 million and total liquidity of approximately $227 million. Before turning to our outlook for 2026, it is important to note that our guidance reflects both the operational progress discussed earlier as well as the capital structure initiatives completed during the fourth quarter of 2025 and the first quarter of 2026.

Our development program is expected to operate 2 drilling rigs during 2026, including 1 rig deployed across our legacy assets in Pennsylvania and Ohio and 1 rig dedicated to the recently acquired Ohio Utica beginning early in the second quarter. This level of activity supports continued production growth while maintaining capital discipline and operational flexibility across both areas.

Looking ahead, we expect to continue advancing development across all areas within our portfolio. And anticipate turning into sales 31 gross wells during calendar year 2026, consistent with the development plan outlined in our investor presentation. In the first quarter of 2026, we expect to turn or oil-weighted wells in line on our Ohio Utica assets. For 2026, we expect net production to average between $345 and $375 MCF per day, representing growth of approximately 70% year-over-year.

Development capital expenditures which are a combination of drilling and completions as well as midstream capital expenditures are expected to range between $450 million and $500 million. With that, I will turn the call back to Zach for closing remarks.

Thank you, David. To summarize, 2025 and early 2026 has been a transformative period for Infinity National Resources as we continue to execute operationally, scale our Appalachian platform through strategic acquisitions and reinforce the balance sheet with new long-term equity markets. We enter into 2026 with a strong operational foundation PAUSE expanded development inventory and a strengthened capital structure. Our position across oil-weighted Ohio Utica, rich gas, Ohio Utica opportunities and dry gas Marcellus and Utica development provides the flexibility to continue delivering sustainable room and value for our shareholders. Operator, please open the line for questions.

[Operator Instructions]

Our first question comes from the line of Michael Scialla with Stephens.

I wanted to ask on your '26 plan. Your CapEx guidance is a fair bit above analyst estimates. Can you talk about any changes you made from -- you gave some soft guidance back in mid-December when you did the call on the Antero acquisition. Any changes that you've made since then? And any things that might be in there that David, you mentioned midstream is built into that, I wanted to see if you could break that out at all.

Michael, it's Zack here. Thank you for that question. I think it's a timely one. First and foremost, I would want to point you back to Slide 7 and 10 of our investor deck showing how well we performed last year. We've had cost improvements from a D&C perspective and continue to have great capital efficiency and EBITDA margin. So this capital guidance range that we're talking about and that you're trying to interpret is not a reflection of drilling cost consents. We continue to execute very well there, and we're gaining scale. So we expect additional synergies and improvements.

What I think is helpful to understand is some things related to the acquisition. First of all, we have an additional 9% of CapEx. Now we took on additional working interest from the Antero deal than what we knew when we were talking before. Also the first pad out of the gate, the English pad will be completed by us in the capital board by us. So that's 19,000 lateral feet on 3 separate wells. So that's a lot of lateral footage with completion activities that are coming to us.

Another point on the Antero deal is we wanted to make sure we had a rig ready to go as quickly as we could, and we didn't want to have the asset closed and be looking forward to. As a result of that effort, we picked up the rig before close, and that rig has been drilling on INR projects. So effectively running 2 rigs across our base business for part of this first quarter. So those things are all adding to it that were a little bit different than when we visited before.

You talked about midstream, I think that's an important component of this, too. And while we don't break that out, we are -- we're more than double the size of our midstream with the acquisitions of Antero and we're actively developing in both areas that would require midstream investments. And so we'll expect to spend money in both areas, PA and Ohio as we build out midstream. And I think for us, we don't break it out because it's a little bit fungible, and it still gives us some flexibility in our pad selection and where we're deploying capital between drilling wells that don't require midstream, maybe you add an extra well to that pad versus somewhere where you need to add midstream so you allocate dollars there.

A couple of other things just to point out, too, is we want to make sure we maintain flexibility in that capital guidance. But what we did last year, which is pickup working interest. Our land group has been incredibly skilled at the ground game and adding in working interest and lengthening laterals. So we don't want to surprise somebody if we end up with the interest or longer laterals than we talked about. And now that we're running 2 rigs, the timing component becomes a little bit magnified where if those rigs gain pace and start drilling faster because we have rigs that are having shorter rig roots because they're staying in Ohio instead of bouncing back and forth between Ohio to PA, for example, and we pulled forward a well into the year. And that's another $10 million to $15 million that hither CapEx budget and those back of the year CapEx spend don't reflect themselves in 2026 production.

So a lot of things going on there. But I think for us, we want to make sure we give ourselves the flexibility to react and be able to plan our business without surprising anybody as other projects come up. And there are certainly capital projects we haven't budgeted before that I think could be interesting, including for the deep dry gas unit.

I appreciate that detail, Zach. I guess, just to clarify, in terms of well cost, you're not anticipating any OFS inflation or anything, you're still anticipating well costs to at least stay flat or maybe even trend down. Is that right?

Yes, that's correct.

Great. And then I wanted to follow up on the -- you mentioned the deep Utica, which you've budgeted for this year. Anything more you can add on that play why you decided to -- I know you guys have kind of gone back and forth on when you were going to drill that first well. I guess, what helped you decide to put it in the 26 plan? And what do you think your exposure there is if the play works.

We wanted to budget for it. We'll still maintain the flexibility to choose to do what or not do it as we see gas prices and other factors. Maybe oil prices ripple through our decision-making process. So we've set ourselves up with a rig that's capable and experienced in doing this. One of the things we wanted to do was make sure we set ourselves up for success to the greatest extent possible, and we're really excited about some of the deep dry gas Utica experience that we've added to our internal staff and to our field staff as well.

When we get to the right project, and we do have a permit name hand and we have a rate April experience drill in this, we'll be positioned to execute.

Michael, this is David Sproule. I think you can look at the development plan that we have and the development of that well would be towards the latter half of this year. We would not anticipate that well coming online this year. I think we've always been excited about the Utica. It has not changed change has only been more excitement about what we see in [indiscernible]. There are plenty of offset development activities to us. We've been watching those. So I think for us, it's just consistent with our overall theme of kind of walking before running with regards to developing it. But we are very excited about the prospectivity therein.

Our next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.

Michael actually took some of the ones I was going to hit at. But I wanted to dig back in on the deep Utica first. It looks like you have a spud plan or you may have recently spud that well in the deep Utica I know there's a Cooper pad in Armstrong County. Can you give kind of any context? Have you spud this well yet? I recognize you don't plan to complete it this year.

But is that definitely happening? Or is it still kind of a TBD.

Yes. So I'll make a sort of technical differentiation here for you. If you're watching stuff online, when you set the conductor, it triggers a regulatory spud. So we view that as really just a preparation for a true spud and don't want to get anybody confused as to what's specifically going on. I think what David said a moment ago is most accurate is that we've got really the capital towards the back half of this year and production really not coming in until next as we look at it today.

The other thing I'd note here, Tim, for you and everybody is listening is when you think about our development in the South Bend field, remember, we have multiple horizons that we are targeting. So one of the good things about our position that is unique is that we have dry gas Marcellus there and dry gas east Utica. And so as we come in and develop Marcellus, we can come back in and develop deep Utica. So consistent with our approach there, consistent with our view of maintaining optionality PAUSE that's kind of what you're seeing and when you see that alert from a regulatory spot.

Okay. Okay. Okay. We'll stay tuned. It sounds like nothing imminent on that front. And then I appreciate the comments on CapEx. So Zack, as my follow-up, we talked about a year ago, and you mentioned Infinity wants to stay nimble, but you can't be schizophrenic as you sort of chase commodity prices cycle times seems to be ever shorter and sort of more violent today. How does the Board think about that balance between sort of chasing kind of what you're seeing on the screens in a day versus the cycle times you have? How nimble can you be? And sort of how locked in is this 2026 program?

Sure. So I'll give a little bit of color as to what we've done and what they expect -- so we -- already this year, we turned in line 4 oil-weighted wells. So it feels like that's -- maybe that's a testament to why you can't be situated in your capital deployment because these wells are now you're very excited to have them on. And if we have been fully focused on natural gas, we would have missed a lot of this exposure. We anticipate another pad coming online by midyear. And so like the oral volumes that we're bringing in, in this calendar year.

As far as how we deploy capital differently, our development plan didn't come together in the last 2 weeks. And our development plan has been thoughtfully put together, presented to the Board. We really like the projects, both in oil and gas. And we always have the slide in our investor deck where you see the returns at different prices. So we'll always evaluate if there's an oil project that we should swap in or tuck-in, but it becomes not necessarily always the most prudent thing for us to do. So we'll take some time here. We'll see if these prices stay. That's a big part of the question. Is this a blip? And we don't want to move the rig from a gas project or an oil project and it turned out to be a head at which we've seen on the gas side from time to time.

So we'll continue to have our land teams and our regulatory teams and our construction teams to be prepared for that optionality, and we'll see what the next quarter rents.

Our next question comes from the line of John Freeman with Raymond James.

Just wanted to flush out maybe sort of how to think about the production cadence as we go through the year. Obviously, it appears to be a pretty back half weighted program with -- you've only got 4 of the 31 TILs coming on in 1Q? And maybe just sort of how to think about how we progress through the rest of the year, just to give us a little a little help on that side.

Yes. I think, John, we think back to some of the comments that Zack made earlier about cycle times, I kind of push you to think about that. When you bring a rig out and you start drilling holes is a good rule of thumb for us is kind of 6 months from spud to turn in line for us, 6 to 7 months after that. So to your point, as we ramp up development, much like what we -- what you witnessed in 2025, we would anticipate a considerable ramp through the middle of the year and into the fourth quarter as well. So we started the year, albeit relatively slow. We've turned it as a kind of noted already 4 wells for very long oil-weighted wells. We will start picking up pace with regards to the turn on lines through the balance of the year.

Perfect. And then just a quick follow-up on that. How many DUCs did you all enter 2026 with?

I think we entered the year with -- I mean the interesting thing here, John, is the timing of where that calendar falls. I think we entered the year with 8 DUCs that we had, and we were in the process of drilling a couple more wells during where December 31 sell. Of those 8 DUCs that we carried into the year, we have turned into sales 4 of them. We turned in 2 wells in Carroll County, and we turned in 2 wells in Gursoy County. And we're actively cooking the remain.

Our next question comes from the line of Sam Cox with RBC Capital Markets.

I just wanted to touch on the rig cadence for 2026. Obviously, given certain macro conditions, what would need to happen to evaluate a potential third operated rig.

That's a great question, Sam. I think we are cognizant of our portfolio and the returns that we have. So we're really excited about that. I think we're probably more likely to maybe consider additional frac crews, I would say that PAUSE drilling rigs at this stage. But it's difficult to say. I mean, honestly, 3 weeks ago, oil prices were a little bit different than they were during the straight kind of considerations that we're seeing right now. So if oil prices stayed extremely elevated, from spot relative throughout the remainder of the year, something that we would evaluate.

But we're not -- I want to caution you to think that we're not windsock fear. We're systematically exploiting the reservoirs that we have in a prudent manner. So we'd like to maintain optionality. We've built into our forecast, the ability to maintain optionality both in natural gas and oil. So we have flexibility to do the right things. We're going to let other people kind of in stock with the commodities and make that determination.

Today, we're just systematically exploiting what we have.

Got it. No, I appreciate that. And then you also recently added some long-term hedges to the disclosure this time. How are you all thinking about your hedging strategy?

Sure. it's always -- hedging is always interesting, right? You always look back at high sight 2020. What I -- everybody is not shocking. Everybody would like to have higher hedging part I think we're not speculating on -- I mean, we're really not speculating on order price or natural gas business. What we do is derisk our development program.

if you look on Slide 8, you can see the returns that we have here for oil weighted or natural gas-weighted projects. So when we can get to a situation, whether it be a swaps collars that we can lock in really attractive discounted returns on investment. We will do that. The other thing I'd note is we stay true to our tenants here. We've talked about hedging when the rig shows up. We talked about hedging, when the completion crews show up Zach was talking about the activities that we had, we entered the year with 8 oil-weighted wells that we were completing and turning into sales.

And so we've layered on hedges. Obviously, some of those hedges are a little bit lower than maybe the spot is on 2027, but not by much. But we are looking to systematically derisk our development plan and lock in those returns as we've indicated to our shareholders. And we've done that. So we're pretty proud of what we've done.

[Operator Instructions]

Next question will come from the line of Nicholas Pope with ROTH Capital.

Fourth quarter saw a big jump in oil volumes, just 3 wells brought online in Ohio. I mean it was obviously I think the strongest quarter you've seen. Just curious if there is anything, I guess, performance wise from the wells over there in Ohio that you all saw that kind of really supported that? Or if it was just really where in the Utica, you guys were we're drilling in the quarter. It's just a really big jump, really solid number. So just kind of curious if that was performance, timing or just location that was kind of driving that really strong oil number.

Well, thank you for noticing. We were really excited with those results, too. And I think we -- the projects that we brought in, in the back half of 2026 -- or 2025, excuse me, were fantastic -- really a testament to the operational team, making sure cycle times were fast and execution of long laterals was done flawlessly. So kudos to them for putting us in a position to talk about these volumes.

And then kudos to the land department for making sure that our working interest was high because volumes are important, but having a high working interest in this volume is even more critical. And I think from a performance perspective, we're -- we don't think these performances are anomalies. That's how we expect to perform. And we're very excited in the way that those projects have looked in the back to...

That makes sense. Jumping around a little bit. I know you didn't provide explicit guidance here, but operating costs, gathering costs were both down kind of throughout the year. Sage acquisition of midstream assets, a lot of capital spend in 2026 implied kind of in the in the midstream businesses. directionally trying to understand where those costs are going with that midstream investment. And is there also going to be kind of line items kind of growing for midstream revenues outside of kind of the operating cost line item -- like how is that going to what are buckets?

Sure. I'm going to take the operating cost question first, and then I'll come back to the midstream revenue question second. With regards to operating costs, what you've witnessed in 2025 is an increased activity in Pennsylvania as well as managing our costs down in Ohio. So let me unpack that just a little bit. Remember, in Pennsylvania on our gas assets, our Marcellus assets are. We don't have -- we own the midstream. So we don't have a meaningful GP&T charge. The second thing is, it's volumetrically, the natural gas wells that we put on are significantly larger than the oil-weighted wells that we put into sales in Ohio, just from a petrophysical aspect. So -- as you think about the blending of that, not only are you blending in a lower cost structure, but you're also blending it in with a higher volume at. So naturally, you're seeing some of that decline happen. We have witnessed declines from an LOE in particular basis in Ohio. We've seen consistent GP&T in Ohio. But on a blending aspect, you're seeing a decline in quarter-over-quarter and year-over-year.

With regards to our overall cost structure for 2025. We would anticipate that to continue as we bring on more natural gas volumes as well as when we bring on more volumes associated with the acquired properties from Antero. Antero properties, again, we own the midstream. So while there is additional PAUSE expenditures associated with fractionation activities on some of the wells. We can reduce our overall blended cost or continue to reduce our overall funding costs by integrating those assets there.

Turning to the midstream side. We do generate some midstream third-party midstream revenues on our system. We've done that. You can see that in the line item for revenues that we have for midstream. It is a great opportunity set for us as we think about the future, not only for our assets in Pennsylvania, but our assets that we've acquired from Antero, we have a very large system. It's currently today we're capable of moving upwards of 1.2 Bcf a day of capacity. So we have a very big midstream system that is definitely on our radar and strategic endeavors to expand volumes associated with third parties onto that system.

And this concludes the question-and-answer session. I'll hand the call back over to Zach for any closing comments.

Thank you all very much for your interest in finite Natural Resources. We're very excited to talk about the quarter and the upcoming year, and we look forward to visiting you again soon. Thank you.

This concludes today's call. Thank you all for joining. You may now disconnect.

Greetings, and welcome to Infinity Natural Resources Third Quarter 2025 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded.

It is now my pleasure to introduce your host, Greg Pipkin, Senior Vice President, [ Corporate ] Development and Strategy. Sir, you may begin.

Thank you, operator. Good morning, and thank you for joining our third quarter 2025 earnings results conference call. With me today are Zack Arnold, President and Chief Executive Officer; and David Sproule, Executive Vice President and Chief Financial Officer. In a moment, Zack and David will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations portion of our website, and we may reference certain slides during today's discussion. A replay of today's call will be available on our website beginning this evening.

I'd like to remind you that today's call may contain forward-looking statements. All statements that are not historical facts are forward-looking statements. Forward-looking statements are subject to a number of risks and uncertainties and many of which are beyond our control that could cause actual results to materially differ from these forward-looking statements. Please review our earnings release and the risk factors discussed in our SEC filings.

We will also be referring to certain non-GAAP financial measures. Please refer to our earnings release and investor presentation for important disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures.

Now over to Zack.

Thank you, Greg, and welcome to Infinity Natural Resources Third Quarter 2025 Earnings Call. We're pleased to share our quarterly operational and financial performance with you today, along with an overview of our ongoing development program and our perspective on the remainder of 2025.

Starting with the highlights from the third quarter. We delivered exceptional results that demonstrate our continued momentum across the Appalachian Basin. We achieved 39% total production growth year-over-year to 36.0 MBoe per day during the quarter. This included 70% growth in natural gas production compared to the third quarter of 2024, reflecting our increased focus on natural gas development during 2025.

Our continued execution is driving operational momentum. We have experienced strong results on our recent projects, including our best producing projects in each of Ohio and Pennsylvania to date. Most notably, we achieved a single day net production record of 47.9 MBoe per day in October. This milestone reflects the consistent execution and commitment to operational excellence that has driven several new company records.

Operationally, we had yet again a very strong quarter, demonstrating our consistent execution throughout 2025. In total, we placed 10 wells into sales during the third quarter comprised of 6 oil-weighted wells in the Ohio Utica and 4 natural gas wells in the Pennsylvania Marcellus. We drilled 93,000 lateral feet and completed 442 stages across 6 wells during the quarter. We continue to emphasize extended lateral development with an average well length of nearly 15,000 feet during the quarter.

On the drilling side, our team improved efficiencies on casing running speed, decreasing the average time by more than 25%. On the completion side, we set a new record for stages pumped in 24 hours on one of our projects in [ Guernsey ] County, exceeding 16 stages in a 24-hour period, reflecting both the quality of our completions design and our team's operational expertise.

On the strategic front, we continue to have success in the ground game acquiring approximately 3,000 net acres during the quarter across approximately 350 transactions, increasing working interest in our active development projects and enhancing future projects. These working interest additions are among the highest returning dollars we invest as we acquire more of each project we are already executing.

Looking at our activity by state. In the Ohio Utica, we drilled 3 wells and completed 377 stages during the quarter, all in Guernsey count. We also turned into sales a 57,000 foot 3-well pad early in October resulting in the first production from our [ Muskingum watershed ] and [ Service District ] acquisition we made earlier this year. In the Pennsylvania Marcellus, we drilled 3 wells and completed 65 stages. Specifically, in July, we began drilling operations on the 50,000-foot 3-well natural gas project that we elected to advance early in the second quarter. We are excited to announce that we plan to turn these wells to sales in the coming weeks representing approximately 6 months from FID to revenue generation.

Taking a step back to look at 2025 as a whole, our team's execution and strong well performance has allowed us to increase our production guidance for full year 2025 to 33.5 to 35 MBoe per day from 32 to 35 MBoe per day. We are also updating our full year total development capital expenditure guidance to a range of $270 million to $292 million, which is inside the higher end of our combined [ D&C ] and midstream CapEx guidance.

We are on track to have turned to sales 23 wells this year, 12 natural gas-weighted wells and 11 oil-weighted wells. This nearly 50-50 split is slightly more gas-heavy than our expectations coming into the year, but demonstrates the unique optionality our strategic positioning in [ Appalachia ]. With a balanced portfolio across oil-weighted Utica assets in Ohio and natural gas-weighted assets in Pennsylvania, we can adapt to varying commodity price environments and execute projects that maximize shareholder returns.

The operational momentum we've built throughout 2025, combined with our strategic asset positioning across both oil and natural gas assets provides a solid foundation as we look ahead to 2026. The strength of our balance sheet remains an invaluable asset and we will continue to be thorough and thoughtful as we evaluate organic and inorganic growth opportunities.

With that, I'll turn the call over to David for a more detailed review of our financial results.

Thank you, Zack. Our third quarter results speak directly to the operational and financial execution during the period. As Zack noted, we delivered a 39% increase in net production to 36 MBoe per day year-over-year. Moreover, as noted earlier, our natural gas production increased 70% year-over-year to 138 MMcf per day for Q3 2025. We anticipate further production growth during the fourth quarter, driven by additional [ turn in ] lines in the period. While driving production growth, we also continued to drive cash operating costs lower to $6.09 per BOE from $9.42 per BOE in the prior year's quarter.

As expected, our [ LOE and GP&T ] per unit metrics continued to decline as we bring on additional natural gas volumes in Pennsylvania. As always, we are focused on EBITDA generation and capital efficiency, delivering best in basin adjusted EBITDA margins and capital efficiency when compared to our Appalachian peers.

We generated adjusted EBITDA of $60 million during the quarter. and an adjusted EBITDA margin of $18.12 per BOE, again, a top-tier result compared to our Appalachian peers. The shift towards natural gas weighting continues to improve our operating cost structure while maintaining leading margins. We expect per unit cost will continue to decline as we accelerate Pennsylvania production.

On capital deployment, we invested $95 million into our business during the quarter, comprised of [ $83.2 ] million in development capital expenditures and $11.8 million in land acquisitions. Again, we anticipate capital spend to decline in the fourth quarter. As Zack noted, our land acquisition strategy continues to deliver results with approximately 3,000 net [ acres ] added during the third quarter and approximately 4,300 net acres acquired year-to-date.

What makes these acquisitions particularly valuable to Infinity is that they increase our working interest in ongoing development projects while expanding our future drilling inventory. From a practical standpoint, the increase in working interest on development wells has effectively added approximately [ 1 net well ] to our 2025 development program. Our development capital [ spend ] for the calendar year is anticipated to be within our prior 2025 guidance. This represents more value for investors at the same spend.

Turning to the balance sheet. Our leverage profile remains exceptionally strong with approximately $71 million in net debt. On October 1, we expanded our borrowing base yet again to $375 million, providing us with $304 million in liquidity.

Turning to 2025 guidance. We are raising our full year net daily production guidance to 33.5 to 35 MBoe per day from 32 to 35 MBoe per day. This is driven by strong well performance and operational successes across our portfolio. We are updating our full year total development capital expenditure guidance to a range of $270 million to $292 million, inside the higher end of our previous combined D&C and midstream CapEx guidance of $249 million to $292 million. Again, we are inside the 2025 CapEx guidance while delivering more net wells for our investors.

Lastly, our Board of Directors has authorized a $75 million share repurchase program, reflecting confidence in our underlying long-term value for our business, the strength of our balance sheet and the undervalued nature of our stock price relative to our performance.

With that, over to Zack to close out our opening remarks.

Thanks, David. To wrap up, our third quarter results reflect the strength and strategic value of our diversified Appalachian operations. Our success this quarter highlights what makes Infinity Natural Resources unique. Our proven ability to optimize development across both our Ohio Utica oil properties and our Pennsylvania Marcellus natural gas assets. We demonstrated this flexibility by successfully executing our accelerated natural gas program while maintaining strong momentum on our oil development, positioning us to [ turn in 23 ] wells in 2025 with a near [ 50-50 gas to oil ] production split. We are exceptionally well positioned to sustain our active development pace into 2026, while continuing to deliver strong returns for our shareholders.

Operator, you may now open up to Q&A.

[Operator Instructions] Your first question today comes from the line of Tim Rezvan from KeyBanc Capital Markets.

First one to dig in with natural gas looking more attractive. I know you've sort of pushed back plans to test the deep Utica to 2026. There's been strong comments from public peers. Can you talk about any plans you may have to test that into what's looking like a stronger natural gas price environment?

Sure. Thanks, Tim. I'll take that question. This is Zack. We haven't announced anything specific to the development plan of the [ deep dry gas Utica ]. And we haven't given any guidance on our 2026 development program at all. So as we continue to plan that, that will be a part of our development of that plan. We are always evaluating what other operators are doing, and we think there's continued momentum for the deep [indiscernible] in our [ South Bend ] area. We're excited about that. It is important to remember that when we drill our first [ Gingell be just ] 1 well of many slows in that year, and we'll be excited about it as we are excited about every project we've developed.

Okay. Okay. That's fair. We'll stay tuned. And then I just wanted to dig in to make sure I heard you correctly, Zack, you said that 3,000 net acres that you added, I believe you said that 350 transactions. I don't know if I heard that correctly, but you've added 4,300 year-to-date. Can you talk to kind of what the ground game, how that's evolving? And I know it may be a little more challenging time to pursue sort of larger opportunities. But can you talk about maybe how that's progressing and how you see that into next year.

Great question. And I want to maintain the statement that we are focused on both, the ground game and larger scale transactions. But to answer your grounding question, we added 3,000 acres over the 350 transactions. I think that's an incredible testament to our teams' ability to stay focused in areas where we see value. I think we have a strategic advantage by being located in the basin that gives us a unique opportunity to be in the neighborhoods and in the communities as we go out and talk to folks [ at ] those transactions that we closed in this are that we added, added additional working interest of projects that are incredibly meaningful to us.

So projects that we're already developing at the back half of this year, we were able to increase our working interest due to the work that a focus on. So really excited about that work, and we'll keep doing this ground game attacks in both areas in Ohio and in Pennsylvania, and we'll keep looking at the order scale in [ Enable ].

Your next question comes from the line of John Freeman from Raymond James.

Nice to see the share repurchase plan, especially at these valuations. Just maybe how you all think about the trade-off between share buybacks versus continued kind of ground game acquisitions.

Yes. John, this is David. I'll take that one. I think there's a couple of points on that. I think first and foremost, the share buyback will not impact our asset development or acquisition strategies at all. I think that's very much a testament to the team and the capabilities that we have and the assets that [ we have ] that we're developing here.

And the second thing I'd say is, the share price is significantly undervalued. And we're being opportunistic here given our long-term view of the business and our focus on allocating capital to maximize shareholder returns at every step. And so, it's a good opportunity for us, and we're excited about executing that on side of all the other assets that we're [ developing ].

Got it. And then my follow-up question, it looks like the amount of natural gas hedges kind of went down each quarter going forward. Maybe can you just speak to that decision?

Yes. We've been pretty well hedged from natural gas. The decline there on natural gas hedges as a percent. Is that your question, John, as a percentage of total [indiscernible].

It looked like, David, at the absolute like volume amount that you all have hedged versus all prior update had gone down the rest of 3Q, 4Q and then also for full year '26. Just the actual volumes that you all have gas hedges on, it looked like that went down.

Sure. We can circle back with you. I think first and foremost, we're pretty well hedged on natural gas through 2025, as you guys can see. I think the change in our percentage of hedging is to continue to highlight the strong well performance that we're having in Pennsylvania. But our strategy overall with regard to hedges, as we kind of talked about at length before, is to really look at the kind of return on investment that we get on these projects and lock in some of those at an FID and then we have sort of uptick those from the have completion crews call. We will continue to execute on that plan there. But we're pretty well hedged through 2025, in particular, on natural gas and then have great exposure to natural gas uptick in the coming years.

Your next question comes from the line of Scott Hanold from RBC.

Yes. I appreciate the fact that it's probably too early for 2026 guidance. But I don't know if, Zack, could you kind of frame it up for us a little bit? Like should we think about like this kind of 1 to 1.5 rig pace you ran this year is a reasonable kind of trajectory and how you think about oil versus gas mix in general? And just help us frame up for what that means on the capital side, too, with the development efficiencies and everything else you're seeing.

Sure. So I'll start by saying we are giving soft guidance yet for what 2026 will look like. We will provide guidance in Q1 to let everybody understand how we're approaching next year and our capital allocation and our pace of business. So to kind of back up from that and just kind of give some framework for folks to be able to think about what our business could look like, though as we still formulate all of our development plans.

We ran 1.2 rigs in 2025, I think you should expect that we remain at least that active in 2026. We are providing splits to our capital allocation right now between gas or oil, but we have very attractive returns in both commodities, and I would expect us to be active in both states next year.

Okay. Got that. And then just to clarify, Zack, I think you said you all reached like [ 47.9 ] MBoe per day in October. Just could you clarify that? Is that a peak rate? Or was that an average? I'm just -- just help me kind of square the circle with. I think you said you expect to see some growth through the fourth quarter. I think guidance for something around [ $43 ] a day. If you're up around [ 48% ], just kind of help us like walk through the timing of the TILs and natural declines coming off in some of the pads you've done.

Sure. So specifically, that number was a daily spot rate that we reported there. We have wells that we will be turning in line this quarter, 3 of them have already happened. That number corresponded [ 3 ] wells coming online. We have 3 additional gas wells that will come online here in pretty fresh time here in the next couple of weeks. So we don't give quarterly production guidance, so it doesn't -- so I can't really help you specifically get to what this quarter is going to be, but I'll just point you back to the production range that we said.

And anything -- sorry, I was just going to make a comment that we've been very happy with our recent well performance, too, and that helps us get through those production records as we go.

Yes. And just to clarify, am I correct, though, the implied kind of 4Q guidance is around [ $43-ish ] somewhere around there that if I take your full year less what you've done year-to-date.

Yes. I don't know -- we don't have a specific quarter number because we haven't necessarily spoken about that. But I would just keep you thinking about how the 33.5% to 35% represents our view of production for the [ year ]

Your next question comes from the line of Michael Scialla from Stephens..

I wanted to ask on your D&C CapEx guide for the year, you took that up at the midpoint a bit. Just want to see how well costs and the pace of development are trending versus your prior expectations?

I think a couple of things there. We've been really happy and proud of our operational team. They have not only delivered this year, but they delivered in an expedient fashion. We're kind of seeing some of that come through with the numbers there. Obviously, the tariffs affecting, but I would tell you that our [ dollar per port basis ] here, is great and actually tracking extremely well to what we anticipated back in March.

I think some of the things that you're seeing with a higher level of spend is reflecting a couple of thoughts. One is, Zack alluded to this in his comments, that we've added additional acreage and working interest. We kind of noted it in the prepared remarks that we provided -- we've effectively added an additional well in that. So as you think about an additional well for us, is a 15,000-foot lateral is a pretty impactful benefit to us from an economic perspective but also kind of does affect the overall expenditure.

The second thing is we have pulled forward some of those natural gas projects and spent some money to prepare for 2020 with regards to our infrastructure aspect. So you're seeing both of those kind of manifest here. But again, we're delivering better results, we're delivering more effective net wells at the same spend.

Sounds good. And I know you had some midstream constraints that you talked about last quarter. At this point, are you running into any kind of constraints midstream or otherwise that could impact your operations going forward?

No, no midstream constraints. We're really excited about the midstream that we're building out on our own for gas assets, as David talked about, spend money there, preparing for this year's gas volumes and [ mix year is gas ] volume. So well positioned there. And our near-term development in Ohio is all some pads that are tied into the pipeline already. So no anticipated issues at it.

Your next question comes from the line of Paul Diamond from Citi.

Just wanted to touch back on the share buyback is kind of the strategy around execution. I mean, you said you think the shares are undervalued, I guess, at what point would you mean further in? Is there a market you have out there? Is it just more relative to now or against internal model? Just how to think about the some timing of that, I guess.

Yes. Paul, this is David. I think first and foremost, I don't think it's surprising to anybody who's listening on this call that we think that our shares are undervalued. I don't think we're going to give today any view of where we would opportunistically utilize our buyback authorization, if you will, at this stage. But we obviously are really happy and excited about the business that we have, the long-term generation of cash that we really anticipate here and think that the shares are significantly undervalued, and we're just going to be opportunistic about rolling them back into the company.

Got it. Makes perfect sense. And then since IPO early this year and kind of as you really commenced on that 1% to 1.5% kind of [ drill pace ]. Are you talking about anything that might have on the upside and the downside surprised you about all results versus your [ resin ] expectations. The decline rates in line, the [ IPs, EURs ], all that stuff.

I think it's important to note that we've been incredibly spot on with our budgeting of these projects from a CapEx perspective and a production perspective. We've been very pleased with the team's ability to make and forecast the -- what these wells are going to do. We are really happy with a couple of the recent projects that are outperforming our base type of assumptions. So those are always nice to have those surprises to the positive. But I'll compliment the team that they've done a tremendous job in preparing for the IPO and executing this year at planning our business and putting out a budget that we compete.

[Operator Instructions] Your next question comes from the line of Nicholas Pope from ROTH Capital.

Another question about the share repurchase. I was just curious in the release, the comment is that it's for Class A shares. I was curious if there was a mechanism for conversion of the Class B shares to be a part of the share repurchase? Or is that -- do they need to be completely separated in kind of the approval process?

I think -- Nick, this is David. I think, first and foremost, our investors, our legacy investors, I should say, are really bullish on this [ story ] for us. And so I don't think you should anticipate any of that any time soon. I think with regards to the share repurchase, the program is starting in and around the Class A shares. So those are the economic shares that are trading obviously. We have about [ 15.6 million ] shares that are trading.

I think it's important to note, at yesterday's close of roughly [ $1,150 ] that would be and the execution of a $75 million share repurchase program, that would effectively claw back or repurchase north of 40% of the Class A shares. So it's a pretty impactful share repurchase program for us. But again, it's just targeted on the shares that are actively trading in the market say.

Makes sense. Is there any -- as you kind of look at that share repurchase and kind of how things are going to progress going forward, is it primarily going to be focused on like the free cash flow that the company is generating. I just want to make sure it's not anything is like as you're going through the development process or spending development capital that this isn't something that's going to increase debt, like that's mostly going to be coming from the generation of free cash flow.

I think from our standpoint, Nick, none of the share repurchase program will impact the active development and strategies of the development plans of the company. So for us, I think that's the most critical aspect of the company that we have. We have a very strong balance sheet. We intend to maintain a very strong balance sheet. We think that is a strategic strength of us to utilize that balance sheet when appropriate and prudent. But again, None of the activities we announced on the share repurchase program will impact our ability to execute on our plan.

And there are no further questions at this time. I will now turn the call back over to Zack Arnold for closing remarks.

Well, thank you very much for joining us today as we share our Q3 results. We appreciate your time and your interest in INR. Have a great day.

This concludes today's conference call. Thank you for your participation. You may now disconnect.