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Good morning, and welcome to the Infinity Natural Resources Second Quarter 2025 Earnings Results Conference Call. [Operator Instructions] 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

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%, averaging 33.1 MBoe per day versus Q1's 26.5. The period's increase in overall production was primarily attributable to a full quarter impact from 5 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 delivered 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 Rubel Dodd pad 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 well and restricted our ability to produce 2 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 3 wells from this pad. Across our entire asset base, we drilled 7 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 8 wells completing 777 stages, roughly 9 stages per day during the quarter. In Ohio, we drilled 5 wells and completed 504 stages during the quarter. We finished completion activities on a 4-well pad in Guernsey County, totaling 77,000 lateral feet that is anticipated to be online during the third quarter. Additionally, we drilled 3 wells from another pad location, representing another 57,000 lateral feet. We are currently stimulating 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 4-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 8 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 3 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 2 oil wells in Q3. As mentioned previously, our frac crew is currently stimulating 3 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 reinforced 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,

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 Marcellus 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.

[Operator Instructions] Our first question comes from Kalei Akamine from Bank of America.

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?

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 can't give -- we're not going to get 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 free 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 plant acquisition recently in the Borealis pipeline is in the predevelopment stage. When you look at these forces, how do you see them shaping demand in the near 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, it's 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. So some of these are very big in their power demands and are basically supplanting a significant portion of what would have been a multiyear, multibillion-dollar pipeline projects. So we look at Ohio, West Virginia and Pennsylvania as great places to produce hydrocarbons, particularly natural gas right now. We think that there's going to be some improvement in our ability to get better pricing compared to the historical differentials that we've seen over time.

Our next question comes from Scott Hanold from RBC Capital Markets.

You all did some small ground game acquisitions this quarter. If you could give us a little bit of color on that and then more bigger picture, obviously, a little bit of commodity price volatility. 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?

Sure. 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 done -- 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 Britney had a lot of success there, our land farms 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 my follow-up, I think this is for David. Could you unpack the LOE costs0 a little bit. I mean you gave a little bit of color, but 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 related LOE to that builds. But are there other drivers to help kind of drive that down? And what are some of the pushes and pulls that you've been seeing there?

Yes. I think we would anticipate that the costs across the board, GP&T, especially to drive lower during the course of this year. We did incur some true-up adjustments from prior periods largely associated with some nonoperated 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.

Our next question comes from Michael Scialla from Stephens.

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 set up for the remainder of the year?

Sure. So kind of -- I'll give a little bit of clarity on what we anticipate CapEx doing. So we're still feeling a little bit of the effects of the 2 rigs and the 2 frac crews. So I would anticipate this quarter's CapEx to be sort of similar to what we've experienced in the last couple. And then it will come down in Q4 as those effects fully work through the system. The 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 doesn't really have a change in our capital need. So from that perspective, we're relatively easy to keep track of as we are continuing to run that rig for the entire year, 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 2 rig activity level in the first half to 1. So you're not really changing fourth quarter from what you had previously anticipated. I guess that's...

That's correct. Yes, that's right. We'll maintain a one rig running for us through the remainder of this year. And one frac.

Got you. And I guess just thinking along the lines longer term, I realize you can -- you got the flexibility to move the rigs and crews back and forth between the 2 plays that are really interchangeable. 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 time frame 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 2 rigs and 2 frac crews. So we effectively had 1.2 rigs that we ran for this calendar year. I think as we look at next year, 2 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 efficiencies. 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 I agree with you that there will be efficiency gains. I just don't think it's going to materialize it in multiple wells additional drilled per year.

Sounds like you move -- your rig time movements are really pretty immaterial at this point even going back forth between the 2 plays. So is that fair?

Our operational team does a great job managing those logistics. And I think they've been -- they've a lot of experience now in moving that rig from one state to the other. So I think they do it quite efficiently.

[Operator Instructions] Our next question comes from Paul Diamond from Citi.

I just wanted to quickly touch base on those third-party midstream constraints in Utica during the quarter. Can you just unpack a little bit what was it? I mean how fast was the remediation? And I guess what is 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 hiccup 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 a location and the rest of the wells are now in line and flowing unconstrained. It's also important to note 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 midstream there. So really feel like this situation has been resolved and is behind us and proud of our team in delivering the production that we did and overcoming this, and we're happy to have those wells flowing unconstrained now.

Got it. Understood. Just touching next on -- as you continue to drill between Ohio and Pennsylvania, I know currently, the D&C costs are pretty even, but can you talk about any puts and takes on how you think about those potentially diverging over time? Or is the geology all still pretty similar?

Just to clarify question. Between drilling in Marcellus gas D&C versus Ohio or Utica?

Exactly, yes.

Yes. I mean I think really what you see impacting D&C costs or whether it's a new pad or return to pad because when you look at the unit, the cost per foot on either of those wells, they are really laying on top of each other within a couple of percent. So you're going to see D&C 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 you look at some of the projects that we've done recently where we've been drilling long laterals, 21,000, 22,000 lateral feet. Those are higher D&C capital projects. So typically, our Ohio wells are a little bit longer than our Pennsylvania wells. So that's where you'd see any difference in D&C spend between the 2 areas is really just a change in lateral length.

Our next question comes from Tim Rezvan from KeyBanc Capital Markets.

I just had one, and it's maybe a request as much as it is a question. With the moving parts on the commodity mix, it looks like some oil that you thought might come online in 2Q has been deferred. It's adding a lot of complexity on understanding the different SKU changes we could 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?

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 recognize that it's not the easiest -- we're not the easiest company for you to model. But 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 through our total turn- in-line schedule. Up to the end of Q2, we'd only turned in line 2 oil wells and one of those was constrained as we talked about there just a second ago. So that -- so now kind of when you look at the end of Q2 and forward, we've already turned in line 2 additional oil wells and removed the constraint from the third. We have 4 additional turn-in-lines that will happen inside of this quarter, and we anticipate 3 additional oil tills at the -- in Q4. So I think you're continuing to see us execute on cycle time and dialing these projects in, and 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 spud wells to say, 7 months, you start to see things come online thereafter. So similarly, on the gas side, by the end of Q2, we turned in line 5 wells. And here in August, we turned in 4 more, and we have 3 additional wells that we are targeting 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. Okay. That's fine. That's fine. I think the market seems to be viewing this as a one-off and not material impact to delay. So I think that's a good thing.

Our next question comes from Scott Hanold from RBC Capital Markets.

Just one follow-up. Those curtailed 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 I think it'd be good to hear your comments on what you're seeing there. It seems like at least through the first 60-plus days that we could see production is actually holding pretty steady at a much higher rate than we would have anticipated. So any color and commentary on that and how that 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 are performing. But what I will say is that we've been very happy with our recent gas development. I think it's reaffirming and going to demonstrate to everybody else, we think we've got the right technical approach between how we drill the wells, complete them, space them, et cetera, for that area so that you'll be able to see continuous, repeatable, predictable gas results there.

We have no further questions in queue. I'd like to turn the call back to

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.