Good morning and welcome to the Infinity Natural Resources second quarter 2025 Earnings Results conference call. All participants are in a listen-only mode. After the speaker's remarks, we will have a question and answer session. To ask a question at this time, please press star followed by the number one on your telephone keypad. As a reminder, this conference call is being recorded. I would now like to turn the call over to Greg Pipkin, Senior Vice President of Corporate Development and Strategy. Thank you. Please go ahead.

Thank you, operator. Good morning, and thank you for joining our second quarter 2025 Earnings Results Conference Call. With me today are Zach Arnold, President and Chief Executive Officer, and David Sproul, Executive Vice President and Chief Financial Officer. In a moment, Zach and David will present their prepared remarks with a question and answer session to follow. An updated investor presentation has been posted to the investor relations portion of our website, and we may reference certain slides during today's discussion. A replay of today's call will be available on our website beginning this evening. I'd like to remind you that today's call may contain forward-looking statements. All statements that are not historical facts are forward-looking statements. Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, that could cause actual results to materially differ from these forward-looking statements. Please review our earnings release and the risk factors discussed in our SEC filings. We will also be referring to certain non-GAAP financial measures. Please refer to our earnings release and investor presentation for important disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures. Now over to Zach.

Thank you, Greg, and welcome to Infinity Natural Resources' second quarter 2025 earnings call. We are excited to present the quarter's operational and financial results and provide you with an update on our development activities and outlook for the balance of the year. Our dedicated team in Appalachia once again delivered and my gratitude goes out to my team for the results they drive time and time again. Let's begin with a review of our second quarter performance. During the period, we delivered production growth of 25 percent, averaging 33.1 in BOE per day versus Q1's 26.5. The period's increase in overall production was primarily attributable to a full quarter impact from five natural gas Marcellus shale wells in Pennsylvania that we turned into sales only days prior to the end of the first quarter. As a reminder, our Marcellus natural gas weighted wells deliver significantly higher production volumes than our Utica oil wells on a BOE basis. In May, we turned into sales one oil-weighted well from our ruble dot patent in ohio it is important to note that we experienced some minor third-party midstream delays during the period these constraints limited our ability to freely flow the wells and restricted our ability to produce two additional oil-weighted wells from the same pad into sales in q2 today we are happy to report that in july the midstream constraints abated allowing infinity to freely flow all three wells from this pad across our entire asset base we drilled seven wells totaling 118 000 lateral feet our activity highlights our continued focus on long lateral development where we drilled on average 16 900 feet per well during the quarter we stimulated eight wells completing 777 stages roughly nine stages per day during the quarter in ohio we drilled five wells and completed 504 stages during the quarter. We finished completion activities on a four-well pad in Guernsey County totaling 77,000 lateral feet that is anticipated to be online during the third quarter. Additionally, we drilled three wells from another pad location representing another 57,000 lateral feet. We are currently simulating this project today, and we anticipate turning these wells online subsequent to the end of the third quarter. On the Marcellus gas side, As discussed on our May call, the company decided to advance its next natural gas project and constructed that pad site during the second quarter. In addition, we drilled a four-well pad totaling 54,000 lateral feet and finished stimulating them in June. I am pleased to announce that those wells were turned into sales in July, less than 30 days after completion activities ended, which is remarkable. This was the project that was accelerated in November of last year. It took us eight months to go from constructing a pad to generating natural gas sales. Let me now provide more color on our third quarter operating plan. Our team continues to execute on its operational plan. Currently, our rig is developing three natural gas wells, roughly 45,000 lateral feet, off the pad we constructed during the second quarter in Pennsylvania. Thereafter, we anticipate our rig to transition to Ohio to drill another two oil wells in Q3. As mentioned previously, our FRAC crew is currently stimulating three oil wells in Ohio. We anticipate that FRAC crew to transition to the natural gas pad we are currently drilling by early Q4. Wrapping up my opening remarks, our results this quarter reinforce the strength of our diversified Appalachian strategy, which focuses on balancing capital allocation across our natural gas and oil opportunities. This flexibility is particularly valuable given today's dynamic commodity environment. We're well positioned for sustained organic growth while maintaining the financial flexibility to complement our core business with accretive acquisitions. With that, I'll turn the call over to David for a more detailed view of our financial results.

Thank you, Zach, and good morning. I wanted to start by reiterating some of the themes from Zach's earlier remarks, we continue to execute on our operating and development plans. As we have noted in the past, we are prudently developing our asset base, focusing always on discounted returns on investment and payback periods while preserving our balance sheet strength and mitigating commodity risk through an active hedge program. Turning to our second quarter 2025 results, we are very proud of our team's performance during this period. We continued to execute on our plan. We increased our net production approximately 28% from the second quarter of 2024 to 33.1 MBOE per day. We generated adjusted EBITDA of $49.6 million during the quarter. Our adjusted EBITDA margin for the period fell to $16.48 cents per barrel of oil equivalent, driven predominantly by a greater weighting towards natural gas production during the period. Operating costs on a per-unit basis further declined during the second quarter to $7.93 per barrel of oil equivalent, compared with $8.14 in the second quarter 2024. Our overall per-unit cost decline was largely attributable to the increase in natural gas development. As we continue to progress into the year, we anticipate further per-unit cost declines as we increase our natural gas production from Pennsylvania. Turning to capital expenditures, we incurred $70.4 million in drilling and completion capital expenditures, along with $2.7 million related to midstream activities during the quarter. We are continuing to execute on our development plan. I am very proud of the performance that our land, operations, and production teams have generated year-to-date. Our outlook for calendar year 2025 remains unchanged. Net production is anticipated to be between 32 and 35 MBOE per day. Drilling and completion CapEx is targeted to be between $240 million and $280 million, while our midstream capital spend is estimated to be between $9 million and $12 million. Turning to the balance sheet, our financial position remains very strong. We have approximately $28 million in net debt outstanding. We have ample liquidity of $322 million, affording us continued operational and strategic flexibility. We remain focused on developing out of cash flow and will continue to position the company to take advantage of opportunities as the market dictates. Thank you. Now I'll hand the call back to Zach to wrap up our prepared remarks. Zach?

Thanks, David. In conclusion, I'm pleased with our second quarter performance which delivered on our operational commitments while showcasing the strategic advantages of our diversified Appalachian platform. Our strong quarter over quarter production growth, driven primarily by our successful Marsales development, demonstrates our ability to execute complex cross-basin programs efficiently and on schedule. What distinguishes Infinity Natural Resources is our proven operational flexibility across our oil and natural gas assets within Appalachia. This quarter, we successfully accelerated a Pennsylvania natural gas project while maintaining steady progress on our Ohio oil development. Our strong balance sheet with minimal net debt and substantial liquidity provides the financial foundation to remain opportunistic. Combined with our deep inventory of premium drilling locations, we're well-positioned to continue optimizing our development sequence based on market dynamics while maintaining our commitment to funding growth through free cash flow the operational excellence demonstrated this quarter reinforces my confidence in our team's ability to deliver consistent value creation for our shareholders operator please begin our q a session thank you if you would like to ask a question please press star followed by the number one on your telephone keypad in the interest of time we ask that you please limit yourself to one question and one follow-up.

Our first question comes from Kalei Akamain from Bank of America. Please go ahead. Your line is open.

Hey, good morning, guys. Zach, David. For my first question, wondering if you can give us any early thoughts on the 2026 activity program. Our base case assumes that capital moderates a bit year over year, sort of helping free cash flow. But at your size, growth still makes a lot of sense here. Any latest thoughts to share?

Good morning, Kalei. Thanks for the question. Where we sit in the current budgeting cycle, it's difficult for me to give much color on what types of wells we're going to be drilling next year, but a few snapshots. I mean, first of all, we've always been strongest when we develop our inventory in both commodities, gas and oil. So we're going to challenge our team to continue to deliver the assets that we can develop in both of those windows. I think you touched on something that you're thinking about similarly to the way we think about it is that as we look at CapEx next year compared to this year, I would not expect it to decrease. I think we're going to continue to look to develop our inventory that we're very proud of and have very high returns and continue to grow the company. So I think we're not going to give 2026 CapEx guidance yet, but I think you are leaning towards the right spot where we're going to continue to stay focused on development and still maintain a strong cash flow.

That's helpful. Really appreciate those comments. For my second question, wondering what your latest thoughts are on in-basin demand and egress around your position in Ohio. There was a power plan acquisition recently and the Borealis pipeline is in the pre-development stage. When you look at these forces, how do you see them shaping demand of the year to medium term?

I get really excited when I think about in-basin demand and how it is being impacted by some of the power gen discussions and AI and all the positive movement there in gas demand. And I think as we look at these, each of these power plants is either converting or in these data warehouses that are coming online. They represent some portion of a pipeline that doesn't have to be built to take gas out of the basin. And so some of these are very big in their power demands and are basically supplanting a significant portion of what would have been multi-year, multi-billion dollar pipeline project. So we look at Ohio, West Virginia, and Pennsylvania as great places to produce hydrocarbons, particularly natural gas right now. And we think that there's gonna be some improvement in our ability to get better pricing compared to the historical differentials that we've seen over time. Helpful. Thanks, Zach.

Thank you.

Our next question comes from Scott Hanold from RBC Capital Markets. Please go ahead. Your line is open.

Yeah, thanks. You all did some small ground game acquisitions this quarter. If you could give us a little bit of color on that and then, you know, more bigger picture. Obviously, a little bit of commodity price volatility. You know, one of your big competitors has been acquired. Can you give us a view of what you see on the M&A landscape at this point in time?

So starting on the smaller acquisitions that we've done, I'm really proud of our land team and their ability to focus the ground game in and around areas where we're operating. So what you've seen us do here over the last quarter has been to add key acreage in both areas, our oil window and our gas window. So helping us further solidify our near-term development, increase working interest in wells that we're going to drill, all things that are critical to our business plan. So very proud of that work that's been done there. And we'll continue to execute on that. And as we think about broader M&A, we continue to be excited and focused on opportunities that come our way. Nothing that I can speak to specifically, but I do think it's an interesting time in the basin in which there have been some transactions that have gotten done, maybe a little more clarity in the market than what we've had in previous years. So we continue to maintain a great deal of focus on opportunity sets down to the ground game that we just talked about, and Brittany's had a lot of success there, our land department's had a lot of success there, and lengthening laterals and such. And we'll continue to do it on the asset side as well, as we see gas assets or oil assets or mixed assets come to market, we'll be prepared to use that balance sheet that we're so proud of to go chase these acquisitions.

Got it. And in my follow-up, I think this one's for David. Could you unpack the LOE cost a little bit? I mean, you gave a little bit of color, but, you know, year to date, it's run a little bit above my expectation, and it does sound like it's going to come down as some of the gas volumes and, you know, related LOE to that build, but are there other drivers to help kind of drive that down, and, you know, what are some of the pushes and pulls, you know, that you've been seeing there?

Yeah, I think, you know, we would anticipate that the costs across the board, GPMT, especially to drive lower during the course of this year. We did incur some true-up adjustments from prior periods, largely associated with some non-operated activities from some of our friends in Ohio that manifested in this period that we do not anticipate going forward. So, you should anticipate us as we continue to put on both oil and natural gas wells throughout the remainder of the period to continue to drive down our cost structure across the board. Thank you.

Our next question comes from Michael Shala from Stevens. Please go ahead. Your line is open.

You mentioned you pulled the project forward from fourth quarter to third quarter, but you kept your budget the same for the year. does that imply that fourth quarter is going to have less activity now than you previously planned or do you stay with the one rig one crew setup for the remainder of the year sure so kind of i'll give a little bit of clarity on what we anticipate capex doing um so we are still feeling a little bit of the effects of the the two rigs and the two frat crews so i would anticipate this quarter's capex to be you know sort of similar to what we've experienced in the the last couple and And then it will come down in Q4 as those effects fully work through the system. So pulling forward of the gas pad and how that impacts our capital projections, I think it's really important to know that from a cost per foot perspective, our gas wells cost almost the exact same as our oil wells. So when we move projects back and forth, it doesn't really have a change in our capital So from that perspective, we're relatively easy to keep track of as we're continuing to run that rig for the entire year uh you know just even if we move one pad in front of the other our overall capex need doesn't change okay so you're just going from the uh the two rig activity level in first half to to one so you're not really um changing fourth quarter from what you had previously anticipated i guess that's that's correct okay yes that's correct we'll Maintain one rig running for us through the remainder of the issue and one practice.

And I guess just thinking along the lines of longer term, I realize, you know, you can, you have the flexibility to move the rigs and crews back and forth between the two plays. They're really interchangeable. Well, I guess from an efficiency standpoint, it would be more ideal to have one in each play. Do you think that's in the cards in the next – I guess what is the timeframe for kind of getting to that level? And what would the efficiency benefit be if you could achieve kind of one rig each play, one crew each play?

So for us, we've always been really sort of a walk-before-run type of company, and we've been running one rig consistently for the last couple of years. This is the first time that for an extended period of time we've run two rigs and two frack crews, so we effectively had 1.2 rigs that we ran for this calendar year. I think as we look at next year, two rigs is probably, for the entire year, is probably more aggressive than what we'll budget and plan for. But I think that we probably will not look to do less than the 1.2 rigs that we ran. Your point of efficiencies of one gas rig and one oil rig, I think that's fair, that if you're not moving a rig as far, you do get a little bit of efficiency. But when you look at the overall calendar and you look at how quickly we're able to move this rig from one pad to another, moving from one state to another isn't additional days necessarily compared to an infield move. so um i agree with you that there will be efficiency gains i just don't think it's going to materialize it in the multiple wells additional drill per year sounds like your move uh your rig time movements are really pretty immaterial at this point even going back forth between the two plays so yeah our operational team does a great job managing those logistics and i think they've been there's a lot of experience now and moving that rig from one state to the other so um so i

think they do it quite efficiently appreciate that thank you thank you for any additional questions please press star followed by the number one our next question comes from paul diamond from city please go ahead your line is open thank you good morning all thanks for taking the call i just want to quickly touch base on those uh third stir third party ministry constraints in unica during the quarter can you just unpack that a little bit what was it i mean how fast was the remediation and i guess where does the expectation that could occur again?

Sure. So first and foremost, I want to acknowledge that we had a 25% production growth quarter over quarter, so very proud of our team for executing on that, even despite a little bit of a midstream pickup there from a third party. I'll also compliment our commercial team for finding a temporary midstream solution that allowed us to get that second well in line and produce it even though it was curtailed for that period of time. Basically, it boils down to a farmer didn't want a pipe going through his field, and we had to reroute around it. And we did that. The pipe has made it to location, and the rest of the wells are now in line and flowing unconstrained. I think it's also important to know that our next several oil projects that we will drill already have pipe to location. They're sort of returned to pad or projects that we'd already intended to do and some midstreams there. so really feel like this uh situation has been resolved and is behind us and proud of our team and delivering the production that we did and and overcoming this and uh we're happy to have those wells flowing that constraint now got it understood um just touching next on as you can see the drill between ohio and pennsylvania i know currently the dnc costs are pretty are pretty even but can you talk about any puts and takes and how you think about those potentially diverging over time or is it geology all still pretty similar um just to clarify question uh between drilling and marcellus gas dnc versus um ohio utica exactly yes yeah i mean i think really what you see impacting dnc costs or whether it's a new pad or return to pad because when you look at the the unit the cost per foot on either of those wells they are they are really you know laying on top of each other within a couple of percent so um you know you're going to see dnc change based on lateral length and based on working interest you're not going to really see a change based on which state we're drilling it in so if you look at some of the projects that we've done recently where we've been drilling long laterals 21 22 000 lateral p those are higher dnc capital projects so you you know typically our ohio wells are a little bit longer than our our pennsylvania wells so that's where you'd see any difference in d and c span between the two areas is really just

a change in lateral life you got it appreciate it our next question comes from tim resband from key bank capital market please go ahead your line is open good morning folks and thank you for taking our question um i just had one and it's maybe a request as much as it is a question um with the moving parts on the on the commodity mix it looks like some oil that you thought might come online and 2Q has been deferred. It's adding a lot of complexity on understanding the different skew changes we can expect with your production. So you said directionally natural gas will become a bigger part of total production. Can you maybe give a little more detail on that? And do you think that's something you should be including in guidance going forward to sort of help the analyst community? Thank you.

So first of all, I do recognize and acknowledge that modeling us is a challenge we have a variable commodity mix and we're dynamic and we're growing so um recognize that uh that it's not the easiest we're not the easiest company for you to model but um i'll say overall we anticipate growth in the third quarter and then additional growth in the fourth quarter compared to q3 so really continuing to see volumes ramp up throughout the year i think it's helpful to kind of think about where we are in the year um through our total turn in line schedule up to the end of q2 we'd only turned in line two oil wells and one of those was on was constrained as we talked about there just a second ago so um so that uh so now can when you look at at the end of q2 and forward we've already turned in line two additional oil wells and and remove the constraint from the the third we have four additional turn in lines that will happen in the inside of this quarter and we anticipate three additional oil tills at the uh in q4 so i think you're continuing to see us execute on cycle time and dialing these projects in and uh you're going to see with the midstream problems abated as we talked about you're going to be able to kind of predict when we spot wells to say seven months you start to see things come online um thereafter so uh similarly on the gas side you by the end of q2 we turned in line uh five wells and uh and here in august we turned in four more and we have three additional wells that we we're targeting uh being in line before the end of the year.

Okay, so as we look to kind of the end of the year, we should assume natural gas may be somewhere between 65% and 70%. Does that seem reasonable? Are you not ready to commit to that?

I don't think at this point we're giving that breakdown, but at this stage, Tim.

Okay, that's fine. That's fine. I think the market seems to be viewing this as a one-off and not material impact, the oil delay. So I think that's a good thing, and I appreciate the comments. Thanks. Thank you.

Our next question comes from Scott Hanold from RBC Capital Markets. Please go ahead. Your line is open.

Yeah, hey, thanks. Just one follow-up. Those Tortella wells that you all brought online a quarter or so ago, based on the state data, I mean, the production looks fairly strong and good. And, you know, I think it'd be good to hear your comments on, you know, what you're seeing there. It seems like, you know, at least through the first 60-plus days that we could see, you know, production is actually holding pretty steady at a much higher rate than we would have anticipated. So, you know, any current commentary on that and, you know, how that, you know, changes your view or your thoughts on your next gas completions as well.

Well, I appreciate the compliment there on our well performance. and we won't get into specifics on how wells we're forming but what i will say is that we've been very happy with our recent gas development i think it's reaffirming and i'm going to demonstrate to everybody else we think we've got the right technical approach uh between how we drill the wells complete them and spacing etc for that area so that you'll be able to see continuous repeatable uh predictable gas results there thanks we have no further questions in queue i'd like to turn the call back to Zach Arnold for closing remarks all right well once again thank you all for your time this morning I appreciate the detailed follow-up questions and we look forward to continuing to explore this company together so thank you this concludes today's conference call thank you for your participation you may now disconnect