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Greetings, and welcome to Infinity Natural Resources First Quarter 2025 Earnings Conference Call. At this time all participants are in a listen-only mode. A brief question-and-answer session will follow the prepared remarks. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Greg Pipkin, Senior Vice President, Corporate Development and Strategy. Greg, please go ahead.

Thank you, operator. Good morning, and thank you for joining our first quarter 2025 earnings results conference call. With me today are

Thanks Greg and welcome to Infinity Natural Resources first quarter 2025 earnings call. I’m pleased to share our operational and financial results for the quarter as well as provide an update on our development activities and outlook. I first want to say how proud I am of my team’s execution during the first quarter. Aside from all the work associated with the IPO, the first quarter of 2025 was the most active operational quarter in our history. We executed and we delivered. Moreover, it was the first harsh winter we’ve experienced in quite some time up here in Appalachia. Being able to drill and complete our projects, as well as maintain uptime on our producing wells in such an environment is a testament to the capabilities and experience of our highly skilled team. With regards to our first quarter performance, we achieved strong operational execution across our portfolio. As I just noted, the first quarter was our most active quarter to date. We turned into sales six wells during the period, one in the volatile oil window in the Ohio Utica and five natural gas wells in the Marcellus Shale in Pennsylvania. We continued to increase our production volumes. Our production averaged 26.5 million [ph] barrels of oil equivalent per day in Q1, a 13% increase compared to fourth quarter 2024. The five natural gas wells were turned in line only days away from the end of the quarter. As such, our production growth in Q1 was largely attributable to our recent oil weighted development in Guernsey County, Ohio where We have added seven long laterals since Thanksgiving 2024, including the one well that we turned into sales in early January. Operationally, we ran two rigs for most of the quarter, drilling eight wells. We TD-ed four of the wells totaling 62,000 lateral feet during Q1 and finished drilling the remaining four in early Q2. On the completion side, we stimulated seven wells completing 522 stages while pumping 4.6 million barrels of water. As an aside, most of those barrels were pumped in the low freezing temperatures. Further breaking down activity by region. In the Ohio Utica, we drilled four wells during the first quarter. As a result, we have now drilled 34 wells into the volatile oil window totaling 420,000 lateral feet. We continue to extend our laterals with our most recent Ohio pad being our longest wells drilled to date, averaging approximately 19,000 feet per well. With the addition of the one well we brought online in Q1, our total operated well count stood at 119 to end the quarter. Further, we exited the quarter with three drilled and completed wells that we have yet to bring online, two DUCs and two WIPs in Guernsey County. All of these wells brought online or in development in Ohio are well hedged. In Pennsylvania, the five natural gas weighted Marcellus wells that we turned to sales totaled 67,000 lateral feet in Indiana and Armstrong Counties. That project was brought online ahead of schedule and in line with our cost expectations. While we are early in production, we are encouraged by the well results to date. Additionally, we opportunistically contracted a second drilling rig in Q1 for our next Marcellus project. The four-well project totaling approximately 54,000 lateral feet is anticipated to be online this summer. Remember, this pad was a farmer’s field back in November 2024. We are very proud of our team’s ability to accelerate and execute on projects like these. We are continuing to ramp our natural gas assets, delivering growth within cash flow while securing high DROIs. All of these projects are well hedged again securing the economics we saw at FID. As a reminder, our hedging program remains a key component of our risk management strategy. For our near-term development projects, we’ve secured hedges covering a substantial portion of anticipated 2025 production, providing meaningful downside protection while maintaining upside exposure. This strategy has allowed us to lock in the attractive economics that we saw. We expect to continue to maintain a dynamic hedging strategy that locks in returns at key stages of a project cycle. Looking at the second quarter, we’re executing as planned and remain on track with the development program embedded in the full year 2025 outlook we provided on our Q4 2024 earnings call. This includes reducing our operated rig count to one rig and moving our drilling operations to our next oil weighted project, a three-well pad in Guernsey County totaling 57,000 lateral feet. On the oil and natural gas projects that we drilled in Q1, we are moving ahead with our planned completion activities across those eight wells during Q2 with two frac crews. Turning now to our full year 2025 development plan, as you’re aware, the macro landscape has shifted since our last update about six weeks ago. Market sentiment remains cautious about the outlook for oil prices in the back half of this year. However, the market remains more constructive regarding natural gas prices. Our unique asset composition and limited obligations allow us to allocate capital as the market dictates. Optionality to advance gas or oil projects rapidly is necessary today, more than in prior periods. In response to the current environment, we have elected to bring forward our next natural gas project. We will be constructing this pad during the second quarter and expect to begin drilling these wells this summer. Concurrently, we are reviewing our oil weighted development plans in the second half of the year and will be flexible with our operations depending on estimated project returns as we progress through our one rig schedule. Taking a step back, what we are experiencing today again highlights the value of our differentiated business model. Our strategic positioning in Appalachia with a balanced portfolio across oil weighted Utica assets in Ohio and natural gas weighted assets in Pennsylvania provides unique optionality in varying commodity price environments. Our strong balance sheet and development planning have allowed us to quickly pull forward projects as highlighted previously that were originally slated for later years. With approximately 60,000 net horizon acres in Pennsylvania and 63,000 in Ohio, we built our success on developing long lateral wells, maintaining a deep inventory of high quality locations and efficiently allocating capital between commodities based on market conditions. Our long-standing relationships with key service providers, combined with the dynamic nature of the Appalachia service market enable us to optimize costs, while maintaining access to high quality equipment and crews. We continue working closely with our service providers to identify additional efficiency opportunities.

Thanks,

Thank you, David. In conclusion, I am extremely pleased with our first quarter performance during which we demonstrated exceptional operational execution despite one of the most challenging winter seasons we faced. Our ability to bring wells online ahead of schedule showcases the strength of our operational capabilities and deep relationships with service providers in Appalachia. What truly sets Infinity Natural Resources apart and what I am particularly excited about is our unique ability to dynamically shift between oil and natural gas development within the same region. This flexibility is proving invaluable in today’s volatile commodity price environment. We’re actively demonstrating this advantage by maintaining our planned second quarter activities, while accelerating our natural gas development plant for the second half of the year. With our robust inventory and strong balance sheet, we have optionality to optimize returns as market conditions evolve. This strategic positioning in both commodities within Appalachia is a true differentiator for our company and our shareholders. Operator, we may now begin the Q&A Session.

Thank you. [Operator Instructions] Our first question comes from the line of Scott Hanold with RBC Capital Markets. Your line is opened.

Thanks. Good morning all. Just if you have a little context around, obviously pulling forward again some of your gas-weighted activity, and so it sounds like obviously you’ll do some of that, at some point in time, summer or fall this year. Just give us a sense of, from your original plan – I am assuming that’s the placing, some Utica activity and when do you think that’s going to have an impact on the production mix? So is it more of a 2026 sort of event that shows up?

Yes, thanks for the question, Scott. So I think you’re right in thinking about that timing is we’ve done now twice this year. We’ve taken gas projects that were going to be done later in our development cycle, pulled them forward in response to the commodity environment that we’ve seen. And I think as you think about production and mix for the first part of this year, it’s going to be driven by the projects that we’re completing and bringing online obviously already or in the next quarter. And projects like that that come online at the back of the year are going to have more of an impact for next year than they will this year.

Okay, thanks for that. And, I guess the other piece of it is obviously, how the Tortola pad, I think it is, was the pad you all put online in the Marcellus in March. Can you give us some sense of like how those are performing initially to your expectation and is it a read through of some of the stuff that you plan here throughout the summer into next year?

Sure. So I’ll start by saying the Tortola wells came online ahead of schedule and in line with our budgets and they’re currently meeting our expectations. And also take a second to compliment the work that was done to make that happen. For a well to come online ahead of schedule like it did in late March, that meant that all the completion activities that were occurring in January and February went off without a hitch. So the team did a fantastic job helping us deliver those volumes sooner. As far as production goes, they are meeting our expectations. We’re very excited about that. And I think that just gives us further confidence in how we view production in that area and would expect future wells to perform similarly.

Thank you.

Our next question comes from the line of Michael Scialla with Stephens. Your line is opened.

Good morning. Wanted to just get your thoughts on how deal flow looks in both your core areas right now. Anything you could say about the acquisition opportunities you’re looking at?

Sure. So, I kind of go back to the roadshow view that we had and think about just being able to deliver growth organically off of our assets for when deals don’t come as quickly. So we’re really proud of that ability to grow. But we did go public to get that currency to help some deal flow come to us. And we have an incredibly strong balance sheet. So where does that put us today? That puts us very active in processes, yet the ability to be patient and not do deals that don’t make sense for us. Our exposure to both oil and gas and our interest in acquiring assets in both of those areas increases our asset opportunities and really lets us continue to be focused on M&A in a time in which commodities are highly variable and that makes occasionally the bid-ask spread tougher on one side or the other. So we remain very excited about the opportunities that are here in the basin. And you’re going to see us continue to be involved in any process that we can find our way into.

Good, thank you. You had some capital expenditures for land in the quarter. Can you characterize what that was mostly just filling into length and laterals? Or was that actually adding acreage in new areas? And is that maybe a good run rate for those kind of expenditures for the remainder of the year?

That’s another great question, Mike. So I think that that’s an appropriate number for a company our size and the type of work that we were doing in this quarter. I think that the acres we were adding are always going to be focused on helping us either increase working interest in units, lengthening laterals, or adding new inventory adjacent to the inventory that we’re already developing. So I think that helps you kind of get a sense as to what we did and what a burn rate might be. But we’re going to continue to look at things that might fall into more of an acquisitions category that we’ll talk about when those things happen that might be in excess of a number like that.

Understood. Thanks,

Our next question comes from the line of John Freeman with Raymond James. Your line is opened.

Good morning, guys. Just following up on Scott’s earlier question. If I kind of go to the Slide 4 you all got in your presentation, the original plan was to be kind of a 60/40 split on pills between oil and gas. And I guess I’m just trying to make sure that I understand the moving parts here where you bring forward the natural gas pad and then you’re reviewing your oil activity in the second half of the year. So I found that slide where it basically just says, it’s kind of 40/40, and then there’s kind of this wedge that’s sort of, I guess, not quite firmed up yet. Just maybe how we should think about kind of that the mix of pills kind of shaking out on that Slide 4, if you’re able?

Sure. John, this is David Sproule. I think first and foremost, every project that we do is based upon our view of this kind of return on investment that we get. We are very well hedged. And as you well know, when we enter into these projects, we lock in and secure those DROIs as we develop our projects. When we look at the back half of the year, we are excited by both our oil and gas projects. But as we kind of did in 2024, one commodity was stronger than the other near term, and so we allocated capital accordingly. We have elected to pull forward an additional gas pad that would be slated to come on during the fourth quarter or early 2025. It just depends on that execution for us. And that would reflect that change in the sort of 60/40 split if you will, where we elected to so plant one oil project and defer that for later in the development schedule for us.

Okay. And then just I guess a follow-up on that because you mentioned, it is, the flexibility you’ve got is quite unique. And like you said last year when oil was strong and gas was [indiscernible] only brought online oil wells. And not trying to jump too far ahead to 2026, but just based off of what’s on that slide, I mean, it’s clear, like at the strip right now, next year the gas returns are off the charts good. Would there be anything else that we should be considering that may either from a delineation perspective in the Utica or something like that, that would potentially cause the mix next year to not be just driven pretty hard on the gas side, just given where the returns are? Is there some other factor that goes into you all kind of decision process?

Sure. I think there’s a couple of things to remember is that, first and foremost with our oil projects, these are very long projects in terms of the lateral lengths that we’re developing. A lot of those projects have costs that are already incurred from other projects that were developed in a different period of time. So pad costs and stuff like that is already related to some of those oil projects in particular. It’s never as good as you think and it’s never as bad as you think when it comes to commodities. And so you have to maintain the flexibility to move quickly. If commodities are telling us to do natural gas projects, we’ll do more of those into the future. Commodities are telling us to do oil, we’ll do those. I think we will continue to execute on some of our oil projects into the future because we are seeing discounted returns on investment that are exceeding these because the laterals are longer and the costs are lower. But that doesn’t mean that we wouldn’t develop natural gas. As you know, John, the natural gas returns that we have are pretty frothy right now with the market that we’re seeing. And so you should anticipate us developing additional gas assets into the future.

Got it. Appreciate it. Thank you.

[Operator Instructions] Our next question comes from the line of Kalei Akamine with Bank of America. Your line is open.

Hey, good morning guys. My first question is on capital as we’re kind of heading into or as we’re kind of thinking about 2026 here. So as you work on kind of reshaping your drilling program in the second half of 2025, are you also considering reshaping how you’re thinking about the capital levels for 2026? The way that we’ve seen it kind of come together here is that 2025 is kind of a growth year, 2026 is kind of a harvest year. Do you agree with that setup? And are you still tracking along that path?

That’s a great question, Kalei. Thanks for asking that. So I think you’re spot on with the beginning and that we are maintaining our CapEx guidance for this year. It’s important to know that if we transition from one commodity to the other, it doesn’t make a material impact on our capital needs because the unit cost and cost per foot, cost to construct pads, et cetera, are very comparable from one to the other. So as we remain flexible there, you don’t have to think very hard about what that means a capital schedule. As far as what does 2026 bring, I think that’s something that we’re going to constantly evaluate. I think right now, we are a growth company, and that’s going to continue to be a big part of our story. We’ll look at the returns that we’re seeing on all of our projects as we continue to get those ready. And as we kind of move through the next quarter or two, we’ll get a firm plan together with the Board and start communicating what we think 2026 looks like. But we like the projects that we’ll have ready, and I think we’ll be able to continue to execute on high return projects, like David said, on both sides of our asset base, whether it’s gas, as right now looks fantastic, or whether it’s oil, as some days looks more exciting than others.

I appreciate that. My follow-up question is a follow-up on the M&A question, and I’m going to ask it a little bit differently. So over the last six months or so, we’ve seen a handful of assets transacted in Northeast kind of around your footprint, and you guys have been open about your willingness to be acquisitive here. What do these deals tell you about the valuations in this market? And do you think that you’re well positioned to create value through M&A with deals in this range?

Yes. I’ll take the first part of that and talk a little bit about how and what I think this says about market, and then I’ll let David talk about how we’re positioned to do some of these things. So as we approach deals, it keeps going back to where we were on the road back in January and talk about how as we view and evaluate assets, it’s important for us to understand what we’re going to be able to do with that asset, whether that means it has undeveloped locations that we’re going to attack or operational improvements that we’re going to be able to bring to bear. We get really excited when we think we can put our fingerprints on something that we transact on. I think that the assets that have traded give us encouragement that gas assets can move in Appalachia as that’s not always been the case as you look back through history. So while we haven’t acquired the couple that you’re thinking about, it gives us a lot of confidence that there are the gap between bid and ask is being bridged in the strip environment that we’re seeing today.

Yes. I mean, I think in terms of valuations, I think we are uniquely positioned. Obviously, you’d always prefer to acquire things at lower, lower multiples. But even at the multiples in which the transactions that you’re kind of noting have traded at, those transactions would have been significantly accretive to us. So from a valuation standpoint, I don’t think any of that – those values discourage us in any capacity. I do think also for every one of these deals that you see in the headline kind of number, there’s also a plethora of deals that you’re not seeing that are smaller in scale and scope that we also are exploring and evaluating as well. So deals will go up and down on valuation, but as

Got it. In fact, David, I appreciate it. Thanks, guys.

Yes. No worries.

Our next question comes from the line of Scott Hanold with RBC Capital Markets. Your line is open.

Hey guys. Just had a couple of quick follow ups here. The first is on the Utica deep gas potential in Pennsylvania. Can you give us your thoughts on when you guys think your first well might be drilled and potentially brought online? And if you’ve seen anything on the ground in terms of performance of some nearby wells, I’d be glad to hear some of that, too?

So great question, Scott. Thank you. So I’ll start maybe with the second part of your question first and say that we’re – we are continuing to be encouraged and excited by the activity that we see from our offset – operators, whether it’s CNX who has really led the way in this play, or Olympus who’s done some fantastic work since the – since their formation and beginning of development activities in this play. So very encouraged and excited about that. I think the Olympus transaction indicates that there’s value placed on deep dry gas Utica. So from a macro perspective, we’re very excited about what we’re seeing surrounding us. And for us, we’re incredibly excited and confident in the potential that this is going to open up even more inventory for us develop. We’re actively evaluating where to slot this into our plan. We want to be thoughtful and nimble, so that takes us a little bit of time to make sure we’ve got it exactly where we want it. I think it’s important to know that our pads are constructed and our infrastructure is prepared for this. So when we pull the trigger and do this, we should be able to control our costs and execute it quite quickly. The rig we have running now and have had running for about two years now, is capable of drilling these wells. So while we don’t have it, and I can’t give any specific guidance as to when we’re going to do this, I think you should know that it’s something we’re incredibly excited about. We’re prepared to execute it when we see the right time to drop it into our drilling program.

So is it more of a sort of a risk sort of assessment you’re making right now, like versus, drilling a Marcellus well? Is it just, you just need to get comfortable with the profile and the risk assessment prior to making that decision?

I mean, there’s risk there, as you know, and offset operators know. I don’t think we’re making this decision based on a risk view. I think it’s just the plan that we put in place right now has been to drill Marcellus wells. We’re executing on that plan and we’ll remain flexible to tuck that in here in the short-to-medium term in the future.

Yes. And Scott, this is David. I think the other side is, remember, when we’ve gone public, we are executing on the plan that we put forward in front of the research community, and it’s kind of a trust and verify concept for us. So we’ve been executing on high DROI projects and we continue to do that. We are actively, actively evaluating the Utica well. We are very excited about the prospectivity of it, and it’s something that we’ll consider in the future here.

Got it. Thanks for that. And really quickly, David, give us a view of like how you think about hedging into 2026, especially with, obviously the pivot to more gas. Are you looking at getting a little bit more done in 2026 and maybe even 2027? And a view on, how you think about hedging oil given the volatility there. And this is more of like forward stuff into like 2026 and 2027.

I think, with our hedging strategy, we’ve been very consistent in our approach. We’ll continue to be such, the projects that we have speaking on the oil side in particular, we will hedge those projects as we, bring the rig in and stimulate activities and then bring it online. I think we have demonstrated that we have approached that and it’s been a rewarding experience for us to lock in those DROIs and mitigate that commodity exposure on volatility. I think we will again continue to do that again. On the natural gas side, our approach is very similar as well that we’re looking at those projects and locking them in. We are excited about where the natural gas prices have moved to, but we’re also cognizant of the history that we’ve seen in both commodities over time. And so our strategy has always been and will remain to be to secure our DROIs or high DROIs, and allow us and our investors the exposure to commodity upside through additional development that we have.

Got it. Thank you.

Thank you. Our next question comes from the line of Michael Scialla with Stephens. Your line is open.

Thanks. Just had a couple follow-ups. Wanted to see if I can get a handle on your activity level. So I think you said you’re at two rigs now and is the plan to let that second rig go after you’re done drilling this Pennsylvania Marcellus pad that I think is the Jost Van Dyke pad. And then you said you’re at two frac crews. Is the plan there to let that second crew go after you’re done with sometime in that, in the second quarter or is that run through the third quarter as well?

No, that’s a great question, Mike, and I appreciate the opportunity to sort of make sure that everybody understands our capital base here. So first and foremost, I think falling back to the we are maintaining CapEx guidance for the year. I think is important to know Q1 was our most active quarter in company history as we ran two rigs and a frac crew and brought a number of wells online. Q2 is going to be comparable and look similar as we drop one rig and that rig has now been released. So we’re down to one rig as we said, we would be back in Q1. But we’re picking up a second frac route to sort of follow-up on the completion activities, that second regenerated. So that’s going to lead to CapEx that’s elevated compared to what we’re going to see in the back half of this year. And just to clarify the remainder of our year’s cadence, we’ll have one rig and a related frac crew taking us through the end of the year.

I appreciate the clarification.

Another great question. So for us, I think it’s important to know that our wells work really well in today’s service cost environment. So we’re not relying on any cost improvements to help us juice returns. This is a gas heavy basin and we’re even getting a little bit gassier this year as we talked about. So as such, we’re not really seeing an activity sort of slumping in the basin. So we’re not really focused on commodity driven capital improvements here. We’re going to work with our ops team, we’re going to work with our service providers to continue to seek efficiencies. We think that’s where we’ve got the best gains that we can make in this year.

That makes sense. Thanks.

And there are no further questions at this time. I would like to hand things back over to

Oh great. Thank you very much, guys. I appreciate you joining us again today and we look forward to another successful quarter. So, we’ll talk to you all again soon.