Infinity Natural (INR) Earnings Call Transcript

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DATE

Wednesday, March 11, 2026 at 10 a.m. ET

CALL PARTICIPANTS

• President and Chief Executive Officer — Zack Arnold
• Executive Vice President and Chief Financial Officer — David Sproule

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TAKEAWAYS

• Net Production -- Averaged 45.3 MBOE per day in Q4, with full-year average of 35.3 MBOE per day, reflecting approximately 46% growth year over year.
• Adjusted EBITDA -- $94 million in Q4 with an adjusted EBITDA margin of $3.76 per Mcfe, or $22.58 per BOE; full year adjusted EBITDA reached $261 million.
• Operating Costs -- Averaged $5.56 per BOE in Q4, which "decline approximately 36%" compared to the prior year, attributed to operational efficiency and higher Pennsylvania gas production share.
• Capital Expenditures -- Incurred $326 million for 2025, comprised of $274.7 million for drilling/completions, $35.5 million for land, and $16.1 million for midstream/infrastructure.
• Acquisitions -- Closed a $1.2 billion acquisition of Ohio Utica assets in February, including associated midstream ownership, and completed the Chase acquisition, increasing working interest in the Pennsylvania South Bend field.
• Strategic Financing -- Issued $350 million in perpetual convertible preferred stock priced above IPO ($21.36/share), with proceeds supporting the Ohio Utica asset purchase and increasing working interest to 60%.
• Year-End Net Debt and Liquidity -- Net debt at year-end was approximately $148 million, with total liquidity of about $227 million.
• Drilling Program -- Turned 23 wells into sales for 2025 (12 in Pennsylvania, 11 in Ohio); spudded nine wells totaling 142,000 lateral feet in Q4 and completed six wells totaling 103,000 lateral feet evenly split between oil-weighted Ohio and gas-weighted Pennsylvania projects.
• 2026 Outlook -- Guidance for average net production between 345 and 375 MMcfe per day, implying roughly 70% growth year over year; plans to operate two rigs and turn in 31 gross wells, with development capital expenditures expected between $450 million and $500 million.
• Cycle Times -- Targets "six to seven months" from spud to sales for three to five well projects, which management positions as among "the fastest cycle times in the industry."
• Hedging -- Locked in oil hedges for 2026 and 2027 using swaps and collars; strategy will continue to adapt to commodity price volatility.
• Midstream Integration -- Owns and develops extensive midstream systems, with capacity to move "upwards of 1.2 Bcf per day", enabling further cost reductions and third-party revenue opportunity.

SUMMARY

Infinity Natural Resources (NYSE:INR) reported a significant scale-up in operations and asset base, highlighted by multiple acquisitions and increased capital allocation toward both oil- and gas-weighted development. The company emphasized a rigorous development plan with increased production cadence, expanding its strategic infrastructure and balance sheet flexibility through preferred equity issuance. Management reiterated intentions to maintain cycle time discipline, respond selectively to commodity price changes, and leverage midstream ownership for both operational cost reduction and incremental revenue streams from third-party volumes.

• Zack Arnold stated, "We have significantly increased production, we have grown our operating cash flow, we have expanded our asset base through acquisitions, we have accessed the capital markets, we have entered into strategic partnerships, and we preserved our operational and financial flexibility."
• David Sproule noted, "We continue to witness our costs decline approximately 36% during the fourth quarter when compared to the prior year."
• Arnold confirmed, "our average well turned into sales exceeded 15,700 lateral feet." in 2025, underscoring continued improvements in drilling efficiency and lateral extension.
• Sproule said the convertible preferred stock structure "limits immediate dilution to existing shareholders and preserves balance sheet flexibility relative to incremental debt."
• Arnold explained, regarding capital guidance, "We have 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 are talking about and."
• The company will begin dedicating a rig to the newly acquired Ohio Utica assets early in the second quarter, with first pad sales expected in that period.
• Arnold stated the development plan retains flexibility to adjust the blend between oil- and gas-weighted projects as commodity markets evolve.

INDUSTRY GLOSSARY

• MBOE: Thousand barrels of oil equivalent; a volume metric for aggregate oil, natural gas, and NGLs converted to an oil-equivalent basis.
• MMcfe: Million cubic feet of natural gas equivalent; standardizes volumes across gas, oil, and liquids for reporting and analysis.
• BOE: Barrel of oil equivalent; combines oil, gas, and NGL volumes on an energy equivalency basis.
• D&C: Drilling and completion; includes all capital and activities required to drill a well and prepare it for production.
• DUC: Drilled but uncompleted well; a well that has been drilled but not yet brought into production.
• GP&T: Gathering, processing, and transportation; refers to costs and services involved in moving produced hydrocarbons to market.
• Type curve: A standardized production profile used to model expected performance of oil and gas wells.
• Turned in line: The process of placing a drilled and completed well into production.
• Perpetual convertible preferred stock: A class of long-term, non-maturing equity security with a feature allowing conversion into common stock under predetermined terms.

Full Conference Call Transcript

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 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 of the most comparable GAAP financial measures. With that, I will turn the call over to Zack.

Zack Arnold: Thank you, Tom, and good morning, everyone. Before I begin, I would 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 Natural Resources, Inc.’s fourth quarter and full year 2025 results and to discuss our outlook for 2026. Overall, 2025 was another transformational year for Infinity Natural Resources, Inc. Importantly, we did what we said we would do during the IPO process. We continued to add scale.

We have significantly increased production, we have grown our operating cash flow, we have expanded our asset base through acquisitions, we have accessed the capital markets, we have entered into strategic partnerships, and we preserved our operational and financial flexibility. We have 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 develop 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 ten years of inventory when developed on a two-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 and 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 allows 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 one drilling rig across our base asset. We added a second rig in January, bringing our total operated rig count to two, 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 MBOE 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 nine wells totaling approximately 142,000 lateral feet, while finishing completions activities and turning into sales six wells totaling 103,000 lateral feet, evenly split between Ohio oil-weighted projects 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 15,700 lateral feet. The longer laterals helped to reduce our per-foot drilling cost. It is not just about drilling longer laterals. It is also about cycle times, getting those wells online, and having them track our anticipated well performance.

We continue to target six to seven months cycle times on our development projects ranging from three to five 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 2025. 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 two 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 on wells turned into sales during the year.

Approximately 30% of our projected wells turned into sales will be on the asset 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 Atero 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 asset.

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 pad from the acquired position to come online during the second quarter. As we begin 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 or G&A. This acquisition represents another milestone for Infinity Natural Resources, Inc. as it is the first time post-IPO 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 advantages.

In conjunction with the Antero transaction, Infinity Natural Resources, Inc. successfully issued $350 million of perpetual convertible preferred stock to two highly respected energy investors, Quantum Capital Group and Carnelian Energy Capital. We believe the strong demand from these investors reflects confidence in both 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 platform. Looking more broadly at the market environment, we continue to see strong structural demand for natural gas-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 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 collars. 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 oils. 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 that balances growth with capital efficiency. Our diversified asset base across our Appalachian platform provides flexibility to allocate capital toward 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.

David Sproule: Thank you, Zack, 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 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 Mcf 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 efficiency 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 metrics. We continue to witness our costs 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 experiencing further declines in our overall cost structure as those volumes are on our wholly owned midstream system.

During 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. 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 security, which is convertible into common equity at $21.36 per share, which is above our IPO price, aligning investors with long-term equity value creation.

This hybrid structure provides permanent equity capital that allowed us to repay a portion of the revolver borrowings used to finance the Ohio acquisition, while also supporting an increase in our working interest of the transaction to 60%. Importantly, the structure limits immediate dilution 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 2025 and 2026.

Our development program is expected to operate two drilling rigs during 2026, including one rig deployed across our legacy assets in Pennsylvania and Ohio, and one rig dedicated to the recently acquired Ohio Utica assets 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 2026, we expect to turn four oil-weighted wells in line on our Ohio Utica asset.

For 2026, we expect net production to average between 345 and 375 MMcfe per day, representing growth of approximately 70% year-over-year. Development capital expenditures, which are a combination of drilling and completion 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 Zack for closing remarks.

Zack Arnold: Thank you, David. To summarize, 2025 and early 2026 has been a transformative period for Infinity Natural Resources, Inc. as we continue to execute operationally, scale our Appalachian platform through strategic acquisitions, and reinforce the balance sheet with new long-term equity partners. We enter 2026 with a strong operational foundation, 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 growth and value for our shareholders. Operator, please open the line for questions. We will now begin the question and answer session.

Operator: A question, press star then the number one on your telephone keypad. We kindly ask that you please limit your questions to one and one follow-up. Our first question will come from the line of Michael Scialla with Stephens. Please go ahead.

Michael Scialla: Hi. Good morning. Wanted to ask about your 2026 plan. Your CapEx guidance is a fair bit above annual assessments. 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 have made since then? And any things that might be in there that, David, you mentioned—you know, midstream is built into that. I wanted to see if you could break that out at all. Thank you.

Zack Arnold: Michael, Zack speaking here. Thank you for that question. I think it is a timely one. First and foremost, I would want to point you back to slide seven and ten of our investor deck showing how well we performed last year. We have 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 are talking about and that you are trying to interpret is not a reflection of drilling cost concerns. We continue to execute very well there, and we are 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 and the capital borne by us. So that is 19,000 lateral feet on three separate wells. So that is a lot of lateral footage with completions activities that are coming to us. Another point on the Ontario deal, we wanted to make sure we had a rig ready to go as quickly as we could, and we did not want to have the asset close and be looking for a rig.

So 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 two 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 is an important component of this too. And while we do not break that out, we more than doubled the size of our midstream with the acquisition of Antero.

We are actively developing in both areas that require midstream investments, and so we will expect to spend money in both areas, PA and Ohio, as we build out midstream. And I think for us, we do not break it out because it is a little bit fungible and it still gives us some flexibility in our pad selection and where we are deploying capital between drilling wells that do not require midstream—maybe you add an extra well to that pad—versus somewhere where you need to add midstream to allocate dollars there.

Couple other things just to point out too is we want to make sure we maintain flexibility in that capital guidance for what we did last year, which is pick up working interest. Our land group has been incredibly skilled at the ground game and adding in working interest and lengthening laterals. So we do not want to surprise somebody if we end up with more interest or longer laterals than we talked about.

And now that we are running two 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 moves because they are staying in Ohio instead of bouncing back and forth between Ohio to PA, for example, and we pull forward a well into the year, and that is another $10 to $15 million that hit your CapEx budget. And those back-of-the-year CapEx spends do not 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 have not budgeted before that I think could be interesting, including for the deep dry gas unit.

Michael Scialla: I appreciate that detail, Zack. I guess just to clarify, in terms of well costs, you are not anticipating any OFS inflation or anything. You are still anticipating well costs to at least stay flat or maybe even trend down. Is that right?

Zack Arnold: Yes. That is correct.

Michael Scialla: Great. And then I wanted to follow up on—you mentioned the Deep Utica, which you have budgeted for this year. Anything more you can add on that play—why you decided to—I know you guys have 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 2026 plan, and what do you think your exposure there is if the play works?

Zack Arnold: Yeah. You know, we wanted to budget for it. We will still maintain the flexibility to choose to do it or not do it as we see gas prices and other factors, maybe oil prices, ripple through our decision-making process. But we set ourselves up with a rig that is capable and experienced at 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 are really excited about some of the deep dry gas Utica experience that we have 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 in hand, we have a rig that is capable and experienced drilling this, we will be positioned to execute.

David Sproule: Hey, 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. You know, I think we have always been excited about the Utica. That has not changed. It has only been more excitement about what we see in the dry gas Utica. There are plenty of offset development activities to us. We have been watching those. So I think for us, it is 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.

Michael Scialla: Sounds good. Appreciate it, guys.

Zack Arnold: Thank you.

Operator: Our next question comes from the line of Timothy A. Rezvan with KeyBanc Capital Markets. Please go ahead.

Timothy A. Rezvan: Good morning, folks, and thanks for taking our questions. Michael actually took some of the ones I was going to hit at, but I want 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 is a Cooper Pad in Armstrong County. Can you give any context? Have you spud this well yet? I recognize you do not plan to complete it this year, but is that definitely happening, or is it still kind of a TBD?

Zack Arnold: Yeah. So I will make a sort of technical differentiation here for you. If you are watching stuff online, when you set the conductor it triggers a regulatory spud. So we view that as really just preparation for a true spud and do not want to get anybody confused as to what is specifically going on. I think what David said a moment ago is most accurate—that we have got it really, like, 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 would note here, Tim, for you and everybody listening is if 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 Deep Utica. And so as we come in and develop Marcellus, we can come back in and develop Deep Utica. So, you know, consistent with our approach there, consistent with our view of maintaining optionality, that is kind of what you are seeing when you see that alert from a regulatory spud.

Timothy A. Rezvan: Okay. Okay. Okay. We will stay tuned. 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, you know, Infinity wants to stay nimble, but you cannot be schizophrenic, you know, as you sort of chase commodity prices. You know, cycle times seem to be ever shorter and sort of more violent today. How does the board think about that balance—sort of chasing kind of what you are 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?

Zack Arnold: Sure. So I will give a little bit of color as to what we have done and what to expect. So we already this year have turned in line four oil-weighted wells. So it feels like that is—maybe that is a testament as to why you cannot be schizophrenic in your capital deployment, because these wells are now—we are very excited to have them on. If we had 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 the oil volumes that we are bringing in this calendar year.

As far as how we deploy capital differently, our development plan did not come together in the last two weeks. You know, our development plan has been thoughtfully put together and presented to the board. We really like the projects both in oil and gas. And you will always have the slide in our investor deck where you see the returns at different prices. So we will always evaluate if there is an oil project that we should swap in or tuck in, but it becomes not necessarily always the most prudent thing for us. So we will take some time here. We will see if these prices stay. That is a big part of the question.

Is this a blip? We do not want to move the rig from a gas project to an oil project, and it turn out to be a headache. We have seen that on the gas side from time to time. So we will continue to have our land teams and our regulatory teams and our construction teams be prepared for that optionality. And we will see what the next quarter brings.

Timothy A. Rezvan: Okay. Thank you.

Zack Arnold: Thank you.

Operator: Our next question comes from the line of John Freeman with Raymond James. Please go ahead.

John Freeman: Morning. Just wanted to flush out maybe how to think about the production cadence as we go through the year. Obviously, appears to be a pretty back-half-weighted program with—you have only got four of the 31 wells coming on in 1Q, and maybe just how to think about how we progress through the rest of the year just to give us a little bit of help on that side.

David Sproule: Yeah. I think, John, you know, we think back to some of the comments that Zack made earlier about cycle times, I would push you to think about that. When you bring a rig out and you start drilling holes, it is a good rule of thumb for us that it is kind of six months from spud to turn in line for us—six to seven months after that. So to your point, as we ramp up development, much like 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, you know, we started the year, albeit relatively slow.

We have turned in, as Zack noted already, four wells—four very long oil-weighted wells. We will start picking up pace with regards to the turn-in-lines through the balance of the year.

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

David Sproule: The interesting thing here, John, is the timing of where that calendar falls. I think we entered the year with eight that we had, and we were in the process of drilling a couple more wells during where December 31 fell. Of those eight DUCs that we carried into the year, we have turned into sales four of them. We turned in two wells in Carroll County, and we turned in two wells in Garza County, and we are actively completing the remainder.

John Freeman: Got it. Thanks, guys. Nice quarter.

David Sproule: Thank you. Appreciate it.

Operator: Our next question comes from the line of Sam Cox with RBC Capital Markets. Please go ahead.

Sam Cox: Hi. Good morning. Thanks for taking my question. I just wanted to touch on the rig cadence for 2026. Obviously, certain macro conditions—what would need to happen to evaluate a potential third operated rig? Thanks.

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

But I want to caution you to think that we are not wind socked here. We are systematically exploiting the reservoirs that we have in a prudent manner. So, you know, we would like to maintain optionality. We built into our forecast the ability to maintain optionality both in natural gas and oil. So we have flexibility to do the right things. But we are going to let other people kind of wind sock with the commodities and make that determination. Today, we are just systematically exploiting what we have.

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

David Sproule: Sure. It is always—hedging is always interesting. Right? You always look back with the hindsight of 20/20. You know, it is not shocking—everybody would like to have higher hedging prices. I think we are not speculating on—I mean, we are really not speculating on oil price or natural gas price. What we do is de-risk our development program. You know, if you look on slide eight, 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 swap or collar, that we can lock in really attractive discounted returns on investment, we will do that.

The other thing I would note is we stay true to our tenets here. You know, we have talked about hedging when the rig shows up. We have talked about hedging when the completion crews show up. Zack was talking about the activities that we had. We entered the year with eight oil-weighted wells that we were completing and turning into sales. So we have layered on hedges. You know, 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 de-risk our development plan and lock in those returns as we dedicate to our shareholders, and we have done that.

So we are pretty proud of what we have done.

Sam Cox: Got it. Appreciate it, guys. Thanks.

Operator: And our next question will come from the line of Nicholas Pope with Roth Capital. Please go ahead.

Nicholas Pope: Good morning. Fourth quarter saw a big jump in oil volumes. Just three wells brought online in Ohio. I mean, it was obviously, I think, the strongest quarter you all have 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 drilling in the quarter. It was just a really big jump. So just kind of curious if that was performance, timing, or just location that was kind of driving that really strong oil number.

Zack Arnold: Well, thank you for noticing. We were really excited with those results too, and I think the projects that we brought in 2026 were—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 those volumes is even more critical. And I think from a performance perspective, we do not think those performances are anomalies.

That is how we expect to perform, and we are very excited with the way that those projects have worked in the back of the year.

Nicholas Pope: That makes sense. Jumping around a little bit, I know you did not provide explicit guidance here. But unit operating cost, gathering cost, were both down throughout the year. SIG acquisition of midstream assets, a lot of capital spend in 2026 implied kind of in the midstream businesses. Directionally, trying to understand where those costs are going with that midstream investment. And is there also going to be line items kind of growing for midstream revenues outside of the operating cost line items? Like, how is that going to be supported? What buckets?

David Sproule: Sure. I am going to take the operating cost question first, and then I will come back to the midstream revenue question second. With regards to operating cost, what you have 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 there, we own the midstream. So we do not have a meaningful GP&T charge. The second thing is 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 are also blending it in with higher volume. So, naturally, you are seeing some of that decline happen. We have witnessed declines from an LOE, in particular, basis in Ohio. We have seen consistent GP&T in Ohio. But on a blending aspect, you are seeing a decline 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 Montero. Antero properties—again, we own the midstream.

So while there are additional expenditures associated with fractionation activities on some of the wells, we can reduce our overall blended cost—or continue to reduce our overall blended cost—by integrating those assets there. Turning to the midstream side, you know, we do generate some third-party midstream revenues on our system. We have 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 have acquired from Antero. We have a very large system. Currently today, we are capable of moving upwards of 1.2 Bcf per day of capacity.

So we have a very big midstream system that is definitely on our radar and strategic in endeavors to expand volumes associated with third parties onto that system.

Nicholas Pope: Got it. That is all very helpful. I appreciate it. I appreciate the time this morning. Thanks, everyone.

Operator: This concludes the question and answer session. I will hand the call back over to Zack for any closing comments.

Zack Arnold: Alright. Thank you all very much for your interest in Infinity Natural Resources, Inc. We were very excited to talk about the quarter and the upcoming year, and look forward to visiting again soon.

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

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