Infinity Natural Resources, Inc. Q2 FY2025 Earnings Call

Good morning, and welcome to the Infinity Natural Resources Second Quarter 2025 Earnings Results Conference Call. 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 Zack Arnold, President and Chief Executive Officer; and David Sproule, Executive Vice President and Chief Financial Officer. In a moment, Zack and David will present their prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations 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 Zack.

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 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 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 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 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 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 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, Zack, and good morning. I wanted to start by reiterating some of the themes from Zack'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 continue to execute on our plan. We increased our net production approximately 28% from the second quarter 2024 to 33.1 MBoe per day. We generated adjusted EBITDA of $49.6 million during the quarter. Our adjusted EBITDA margins for the period fell to $16.48 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 for 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 had 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 Zack to wrap up our prepared remarks.

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.

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?

Thank you for your question. In the current budgeting cycle, it's challenging for me to provide specific details on the wells we plan to drill next year. However, I can share a few key points. Historically, our strength has come from developing our assets in both gas and oil. We will continue to push our team to deliver on both fronts. Regarding capital expenditures for next year compared to this year, I do not expect a decrease. Our focus will remain on developing our inventory, which we are proud of and that yields high returns, to support our growth. While we won't provide guidance for 2026 CapEx just yet, you are correct in noting that we will remain focused on development while maintaining 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 generation 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 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 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 have a lot of success there. 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 costs 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 costs across the board, GP&T, especially, will 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 colleagues 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 setup for the remainder of the year?

Sure. I'll provide some clarity on our anticipated capital expenditures. We're still experiencing some effects from the two rigs and two frac crews. I expect this quarter's capital expenditures to be similar to what we've seen in the past few quarters, and then it will decrease in the fourth quarter as those effects fully dissipate. It's important to note that from a cost-per-foot perspective, our gas wells cost almost the same as our oil wells. Therefore, moving projects around does not significantly change our capital needs. So from that viewpoint, it’s relatively straightforward to track our budget, as we will continue to operate that rig throughout the year. Even if we shift the timing of our projects, our overall capital expenditure requirements will remain unchanged.

Okay. So you're just going from the two rig activity level in the first half to one. So you're not really changing the fourth quarter from what you had previously anticipated. I guess that's...

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

I understand. Considering the long-term perspective, I recognize that you can move the rigs and crews between the two interchangeable plays. From an efficiency viewpoint, it would be better to have one rig in each play. Do you envision that happening soon, and what would the timeline be for achieving that? Also, what efficiency gains do you anticipate if you have one rig and one crew in each play?

We have always approached our operations gradually. For the past couple of years, we have consistently operated one rig. This year, for the first time, we ran two rigs and two frac crews for an extended period. We effectively ran 1.2 rigs throughout this calendar year. Looking ahead to next year, planning for two rigs for the entire year may be overly ambitious, but we intend to maintain at least the 1.2 rigs we've been running. Regarding the efficiencies of operating one gas rig and one oil rig, it's reasonable to expect some gains since moving a rig shorter distances can lead to efficiencies. However, when we consider the entire calendar and how swiftly we can relocate a rig from one location to another, moving across states doesn't necessarily add significant time compared to moving within a field. I agree there will be efficiency improvements, but I don't expect them to result in significantly more wells being drilled each year.

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

Our operational team does an excellent job managing logistics, and they have gained considerable experience in relocating the rig from one state to another. I believe they handle it quite efficiently.

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 not wanting 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 the ongoing drilling between Ohio and Pennsylvania, I know currently the drilling and completion costs are fairly similar, but can you discuss any potential differences you foresee over time? Or is the geology still relatively uniform?

Just to clarify the 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 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 two 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?

I acknowledge that modeling our company can be challenging due to our variable commodity mix and our dynamic growth. However, we expect to see growth in the third quarter, with even more in the fourth quarter compared to Q3. We are seeing our volumes ramp up as the year progresses. Up to the end of Q2, we had only turned in two oil wells, one of which was constrained. Moving forward from the end of Q2, we have turned in two more oil wells and removed the constraint from the third well. This quarter, we plan to turn in four additional oil wells and anticipate three more in Q4. We are executing well on our cycle time and optimizing these projects, and as midstream issues have been resolved, you can expect more predictability regarding when we will begin drilling wells, with online production following about seven months later. On the gas side, by the end of Q2, we had turned in five wells, and in August, we turned in four more, with three additional wells targeted for activation before the year ends.

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 that 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 Zack 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.