Infinity Natural (INR) Q3 2026 Earnings Call Transcript

DATE

Tuesday, Nov. 10, 2026

CALL PARTICIPANTS

• Vice President of Investor Relations - Thomas Marchetti
• President and Chief Executive Officer - Zack Arnold
• Executive Vice President and Chief Financial Officer - Cary Baetz

TAKEAWAYS

• Total Production -- 431.7 million cubic feet equivalent per day, representing a 100% increase year over year driven by the integration of the Ohio acquisition.
• Oil Production -- 14,000 barrels per day, a 79% increase year over year reflecting a strategic shift toward liquids-rich development.
• Natural Gas Production -- 282.6 million cubic feet per day, growing 104% year over year as assets acquired from Antero were integrated into operations.
• Adjusted EBITDAX -- $137.7 million, a record for the company attributed to higher volumes and a favorable liquids mix.
• Net Loss -- $0.4 million, including $63.2 million of mark-to-market hedge losses during the third quarter.
• Controllable Cash Costs -- $1.45 per Mcfe, declining 8.2% sequentially from $1.58 per Mcfe due to increased midstream system throughput.
• GP&T Expenses -- $0.82 per Mcfe, a 12% sequential decline driven by 70% of gross operated natural gas volumes moving through internal infrastructure.
• Midstream Utilization -- 35%, increasing from 29% in the second quarter as higher production volumes leveraged available system capacity.
• 2026 Production Guidance -- 355 million to 375 million cubic feet equivalent per day, with management narrowing the range toward the higher end.
• 2026 Capital Guidance -- $450 million to $475 million, with expected spending at the lower end of the range despite cost pressures in the industry.
• Synergy Capture -- Exceeding $25 million for 2026, primarily through development optimization such as drilling from existing pads and connecting acquired water systems.
• Maximum Lateral Length -- Nearly 24,000 feet, drilled with a single bit to increase reservoir exposure and value capture per well.
• Net Leverage -- 1.1x, maintaining a strong balance sheet with no borrowings outstanding under the revolving credit facility.
• Liquidity -- $901.2 million, consisting of $26.2 million in cash and $875.0 million in available borrowing capacity.
• Realized Oil Price -- $65.63 per barrel after derivative effects, compared to an unhedged realized price of $77.82 per barrel.
• Realized Natural Gas Price -- $2.83 per Mcf after derivative effects, providing a premium to the unhedged price of $2.18 per Mcf.
• NGL Realized Price -- $35.55 per barrel after derivative effects, reflecting favorable liquids marketing during the period.
• Development Capital Expenditures -- $105.9 million for the third quarter, focused on drilling, completions, and midstream infrastructure.
• Land and Other Capital Expenditures -- $20.3 million, supporting the company's ground game and inventory expansion through leasing.
• Senior Notes -- $550 million in 7.625% notes due 2031, which were issued to restructure debt and support the Antero acquisition funding.

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RISKS

• Arnold noted that the company has experienced "upward pressure on service costs with diesel and other things," which could impact development capital efficiency if prices remain elevated.
• Arnold stated that "a company our size is always subject to timing," noting that the timing of turn-in-lines for new wells could cause quarterly production fluctuations, specifically citing a potential dip in the fourth quarter.

SUMMARY

Infinity Natural Resources, Inc. (NYSE:INR) reported record third quarter production and financial results, signaling a successful transition from the integration of its Ohio assets to full-scale execution. Management stated that the integration has delivered significant operational leverage, allowing the company to lower controllable cash costs sequentially while doubling total production volumes year over year. The company is prioritizing its liquids-rich inventory in the current commodity environment, which helped drive a record $137.7 million in adjusted EBITDAX. Management indicated that its integrated midstream system, which currently has approximately 1 billion cubic feet per day of throughput capacity, remains a critical structural advantage for organic growth and future strategic acquisitions. With over $900 million in liquidity and a leverage ratio of 1.1x, the company stated it is prepared to act on further M&A opportunities that meet its rigorous underwriting criteria for long-term accretion.

• The company recently completed stimulation of its first deep dry gas Utica well, with management expecting it to turn inline by the end of 2026.
• CEO Arnold stated, "We recently drilled our longest lateral at nearly 24,000 feet, all of which was done with a single bit," highlighting improvements in drilling efficiency.
• Management noted that the REX Zone 3 firm transport contract provides a marketing advantage, with CFO Baetz estimating a 15% to 25% net realization pickup over in-basin pricing.
• The company eliminated two planned vertical well pads by utilizing U-turn well designs, which reduced construction, pipeline, and facility costs.
• Management is evaluating dual fuel utilization for drilling rigs and frac fleets to counteract diesel cost inflation in the 2027 budgeting cycle.
• CEO Arnold emphasized that the company's M&A strategy focuses on long-term accretion and adding volume to the midstream system rather than pursuing scale for its own sake.
• CFO Baetz indicated that the 2027 budget will be built from the bottom up on an economic basis, allowing for capital allocation flexibility between oil and gas projects.

INDUSTRY GLOSSARY

• Adjusted EBITDAX: A non-GAAP financial measure used in the energy industry that adds back exploration expenses to EBITDA.
• GP&T: Gathering, processing, and transportation costs associated with moving oil and gas from the wellhead to market.
• Mcfe: One thousand cubic feet of natural gas equivalent, a unit of measure used to express the energy content of a mix of natural gas and liquids.
• MMcf/d: Million cubic feet per day, a standard measure of natural gas production volume.
• REX Zone 3: A specific segment of the Rockies Express Pipeline that serves markets in the Midwest and allows producers to access premium pricing outside the local basin.
• Utica Shale: A geological formation in the Appalachian Basin containing significant reserves of natural gas, natural gas liquids, and crude oil.
• Lateral: The horizontal part of a wellbore that extends through the producing reservoir to maximize contact and production.
• Turn-In-Line (TIL): The process of connecting a completed well to a gathering system to begin commercial production.

Full Conference Call Transcript

Operator: 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.

Thomas Marchetti: 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.

Zack Arnold: 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.

Cary Baetz: 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.

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

Scott Hanold: 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.

Cary Baetz: 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?

Scott Hanold: 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.

Cary Baetz: 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.

Scott Hanold: 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?

Zack Arnold: 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.

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

John Annis: 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?

Cary Baetz: 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.

John Annis: 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?

Zack Arnold: 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.

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

John Freeman: 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?

Zack Arnold: 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.

John Freeman: 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?

Zack Arnold: 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.

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

Timothy Rezvan: 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?

Cary Baetz: 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.

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

Cary Baetz: Yes. Yes, sir.

Timothy Rezvan: 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?

Zack Arnold: 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.

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

Michael Scialla: 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?

Zack Arnold: 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.

Michael Scialla: 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?

Cary Baetz: 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?

Zack Arnold: No, you covered it.

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

Paul Diamond: 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?

Zack Arnold: 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.

Cary Baetz: 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.

Paul Diamond: 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?

Zack Arnold: 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.

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

Zack Arnold: 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.

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

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