Hello everyone, thank you for joining us and welcome to Infinity Natural Resources' second quarter 2026 earnings call. After today's prepared remarks, we will host a question and answer session. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. 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 second quarter 2026 earnings conference call. With me today is Zack Arnold, our present 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 Kerry Bates and Andrew Judge to Infinity Natural Resources. Effective August 12th, Kerry 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. Kerry 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 EBITDA 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 three rich gas wells from our Antero acquisition and seven other volatile oil wells. On the operating front, we spotted nine wells, including four volatile oil wells in Ohio, two rich gas wells in Ohio, two 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 profit 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 seven wells. This includes a four-well pad we expect to turn in line in the coming days in the volatile oil window and a three-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 RECS 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 liquid side, we continue to see growing optionality within 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 REC 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 Ontario acquisition. as well as the increase in overall volumes. Excluding firm transportation costs, GP&T expense was 69 cents per MTFB 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. Our six to seven 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 70% 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 incompletions 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.

We will now begin the question and answer session. Please limit yourself to one question and one follow-up. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. We ask that you pick up your handset when asking a question to allow for optimum sound quality. If you are muted locally, please remember to unmute your device. Please stand by while we compile the Q&A roster. Your first question comes from the line of Tim Resvin with KeyBank Capital Markets. Your line is open. Please go ahead.

Good morning, everybody. Thank you for taking our questions. I want to start, Zack, on slide 11. We appreciate that the table you all provide with till timing across the asset base. You know, we can see there's a clear oilier skew, you know, to summer, fall tills, and then some gassier tills 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 tills?

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. We're 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 and others. I think the timing should shape up well, but it isn't us trying to seek a proper time to turn a gas well on because of a theoretical gas price.

Okay, that's fair. As my follow-up, I wanted to try to respectfully ask about the executive changes that were announced last night. I know you limited 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. Kerry 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 scaled growth that we are seeking.

Okay, fair enough. Thank you.

Your next question comes from the line of Michael Scialla with Stevens. Your line is open. Please go ahead.

Morning, Zack and Tom. Zack, you gave us some capital efficiency numbers year over year. I want 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 and cost-wise relative to the prior operator, and have you seen enough Will 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 three 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 three wells and have moved it to another pad. So this is, we're starting to see the full benefits of us having one rig in one 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 Intero had per foot, about 1,000 pounds of sand per foot more than Intero. 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. It sounds like you're going to update your, I think you had a synergy target there, annual synergy target of $25 million. We're going to get an update on that down the road here.

Yeah, 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 two pads from the old drilling plant, the Ontario Drilling Plant. So that's allowed us to eliminate and the rest of the industry.

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 to work with them as we move our volumes.

Okay. Fair enough. Thank you.

Your next question comes from the line of Paul Diamond with Citi. Your line is open. Please go ahead.

Thank you. Good morning, all. Thanks for taking the call. You talked about recent improvements in the kind of frac design. I guess in the near term, what do you see kind of the next opportunity beyond the recent tweaks? Is it in is it matter length? Is it in profit 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 Baltimore 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 measured 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 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 two 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 just talked about some ramp up in the midstream utilization, but also some opportunities around, you know, potential third-party utilizations. I guess, can you give any, like, detail on a potential timeline or kind of opportunity set you there, or you see there for, you know, ramping that, the third-party side of that equation?

Yeah, 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, lets us have very low break evens, 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 Those are effectively 100% working interest units, so they don't really generate a lot of 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, our own cost controls, and we'll let the third party revenues show up when they're there.

Got it. Some more in-house in the near term, but potential opportunity down the street. Understood. Appreciate your time. I'll leave it there. Thanks, Paul.

Your next question comes from the line of Sebastian Almodovar with Raymond James. Your line is open. Please go ahead.

Hey, good morning and thank you for taking my questions. My first question has to do with your production guidance. You guys basically 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. I 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. Thank you. And then as a follow up, aside from diesel related expenses, you know, what is your view on potential service cost inflation during the second half of 26?

Now, a 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.

Great, thank you.

Your next question comes from the line of John Annis with Texas Capitol. Your line is open, please go ahead.

Hey, good morning all and thanks for taking my questions. 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 Ontario 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 a premium pricing and allows us to make sure our development can continue to move.

I appreciate that, Kohler. 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 sticks. 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.

I appreciate the time. I'll turn it back.

Thank you.

A reminder, if you would like to ask a question, Please press star 1 to raise your hand. Your next question comes from the line of Nicholas Pope with Roth Capital. Your line is open. Please go ahead.

Good morning, everyone. Good morning, Nick. Yeah, 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 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 increased the past few quarters. I think it was 25% to 35% utilization the last two 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. 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 waiting. 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. 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 break-evens. 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.

I appreciate that, Zach. I'll let you go. Thank you. Thank you.

Your next question comes from the line of Michael Sciallo with Stevens. Your line is open. Please go ahead.

Yeah, I just want 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. Let's see if there's any update there.

Sure. So I think, thank you for that question. We're excited to talk about the D-Drag S 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. 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 three 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.

Sounds good. Thank you.

Thank you.

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. Have a great day.

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