Infinity Natural Resources - Earnings Call - Q2 2025

Executive Summary

• Q2 2025 revenues were $74.48M, down sequentially from Q1 ($85.17M) but up year over year vs Q2 2024 ($70.44M); production rose 25% Q/Q to 33.1 MBoe/d on Pennsylvania Marcellus gas wells, while mix shifted more heavily to gas, pressuring per‑Boe margins.
• Versus S&P Global consensus, INR missed on revenue ($83.39M est. vs $74.48M actual, −10.7%) and on “Primary EPS” ($0.46 est. vs −$1.89 actual); however, company‑reported GAAP EPS was $1.18, reflecting an Up‑C structure/NCI and methodology differences that can create variance versus data providers.
• Guidance unchanged: 2025 net production 32–35 MBoe/d; D&C capex $240–$280M; midstream capex $9–$12M. Management accelerated a gas project into Q3 and reiterated operational flexibility across oil and gas assets.
• Key catalysts: accelerating gas development (near‑term volume growth), improving in‑basin demand (AI/power gen), and clarity on commodity mix trajectory; near‑term overhangs include lower realized prices per Boe, per‑Boe margin compression, and consensus misses.

What Went Well and What Went Wrong

• What Went Well

  • Production growth +25% Q/Q to 33.1 MBoe/d; five Marcellus wells from late Q1 drove volumes, and one Utica oil well turned to sales in May; four more PA gas wells and two OH oil wells turned to sales in July, supporting 2H ramp.
  • Balance sheet/liquidity: net debt ≈$28.1M, liquidity $321.9M as of 6/30/25, providing flexibility to pursue accretive growth.
  • Operational flexibility highlighted: “Our unique asset composition provides us with the agility to adjust development timing and weighting as market conditions evolve” — Zack Arnold, CEO.

• What Went Wrong

  • Mix shift to gas compressed economics: Adjusted EBITDAX fell to $49.6M (from $57.2M in Q1) and Adjusted EBITDAX margin to $16.48/Boe, with management citing greater gas weighting as the driver.
  • Midstream constraints delayed two oil wells in Q2 (since remediated in July); management noted temporary curtailment and a reroute that is now resolved.
  • Consensus misses: revenue (−10.7%) and S&P Primary EPS miss (−$2.34), which may add modeling uncertainty given Up‑C/NCI per‑share methodology differences vs company GAAP EPS ($1.18).

Transcript

Speaker 3

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. Greg, you please go ahead.

Speaker 0

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.

Speaker 1

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 derive 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 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 Rubel Bob 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 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 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.

Speaker 5

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 continued 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 an adjusted EBITDA of $49.6 million during the quarter. Our adjusted EBITDA margin 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 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 CAPEX, 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 Zack to wrap up our prepared remarks. Zack?

Speaker 1

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.

Speaker 3

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 Kaleinoheaokealaula Scott Akamine from BofA Securities. Please go ahead. Your line is open.

Speaker 2

Hey, good morning, guys. Zack, David. For my first question, I'm 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. At your size, growth still makes a lot of sense here. Any latest thoughts to share?

Speaker 1

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. First of all, we've always been strongest when we develop our inventory in both commodities, gas and oil. We're going to challenge our team to continue to deliver the assets so 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.

We can't give, 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 free cash flow.

Speaker 2

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 positioned recently, and the Borealis pipeline is in the pre-development stage. When you look at these forces, how do you see them shaping demand in the near to medium term?

Speaker 1

Yes, I get really excited when I think about inpatient 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. I think as we look at these, each of these power plants that'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. 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 projects. 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.

Speaker 2

Helpful. Thanks, Zack.

Speaker 1

Thank you.

Speaker 3

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

Speaker 4

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?

Speaker 1

Sure. 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. 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, helping us further solidify our near-term development and increase working interest in wells that we're going to drill, all things that are critical to our business plan. I'm very proud of that work that's been done there, and we'll continue to execute on that. 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. We continue to maintain a great deal of focus on opportunity sets down to the ground game that we just talked about. Britney's had a lot of success there. Our land department's had a lot of success there in 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.

Speaker 4

Got it. Thanks. In my follow-up, I think this one's for David. Could you unpack the LOE costs 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. It does sound like it's going to come down as some of the gas volumes and related LOE to that build. Are there other drivers to help kind of drive that down? What are some of the pushes and pulls that you've been seeing there?

Speaker 5

I think you know 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 non-operated activities from some of our friends in Ohio that manifested in this period that we do not anticipate going forward. 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.

Speaker 4

Thank you.

Speaker 3

Our next question comes from Michael Stephen Scialla from Stephens Inc. Please go ahead. Your line is open.

Speaker 4

Good morning. 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 the 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?

Speaker 1

Sure. I'll give a little bit of clarity on what we anticipate CAPEX doing. We are still feeling a little bit of the effects of the two rigs and the two frac crews. I would anticipate this quarter's CAPEX to be sort of similar to what we've experienced in the last couple. 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. When we move projects back and forth, it doesn't really have a change in our capital need. From that perspective, we're relatively easy to keep track of as we're 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.

Speaker 4

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

Speaker 1

That is correct.

Speaker 4

After. Okay.

Speaker 1

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

Speaker 4

Gotcha. I guess just thinking along the lines of longer term, I realize you know, you have the flexibility to move the rigs and crews back and forth between the two plays. They're 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 timeframe for kind of getting to that level? What would the efficiency benefit be if you could achieve kind of, you know, one rig each play, one crew each play?

Speaker 1

Yeah. For us, we've always been really sort of a walk-before-run type of company. You know, 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 frac crews. We effectively had 1.2 rigs that we ran for this calendar year. I think as we look at next year, two rigs for the entire year is probably more aggressive than what we'll budget and plan for. 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.

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. I agree with you that there will be efficiency gains. I just don't think it's going to materialize in multiple wells additional drilled per year.

Speaker 4

It sounds like your rig time movements are really pretty immaterial at this point, even going back and forth between the two plays. Is that fair?

Speaker 1

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

Speaker 4

Appreciate it, Zack. Thank you.

Speaker 1

Thank you.

Speaker 3

For any additional questions, please press star followed by the number one. Our next question comes from Paul Michael Diamond from Citigroup Inc. Please go ahead. Your line is open.

Speaker 4

Thank you. Good morning, all. Thanks for taking the call. I just wanted to quickly touch base on those third-party midstream constraints that you need to address during the quarter. Can you just unpack that a little bit? What was it? I mean, how fast was the remediation? What is the expectation that could occur again?

Speaker 1

Sure. First and foremost, I want to acknowledge that we had a 25% production growth quarter over quarter. I am very proud of our team for executing on that, even despite a little bit of a midstream hiccup there from a third party. I will 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 did not want a pipe going through his field, and we had to reroute around it. We did that. The pipe has made it to the location, and the rest of the wells are now in line and flowing unconstrained.

I think it is also important to know that our next several oil projects that we will drill already have pipe to location. They are sort of returned to pad or projects that we had already intended to do and had some midstreams there. I really feel like this situation has been resolved and is behind us. I am proud of our team in delivering the production that we did and overcoming this. We are happy to have those wells flowing unconstrained now.

Speaker 4

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

Speaker 1

Just to clarify the question, between drilling in Marcellus Shale gas DMC versus Ohio oil Utica?

Speaker 4

Exactly, yes.

Speaker 1

Yeah. I mean, I think really what you see impacting DMC costs is 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 %. You know you're going to see DMC 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. You look at some of the projects that we've done recently where we've been drilling long laterals on one 22,000 lateral piece. Those are higher DMC capital projects. Typically, our Ohio wells are a little bit longer than our Pennsylvania wells. That's where you'd see any difference in DMC spend between the two areas, it's really just a change in lateral length.

Speaker 4

Got it. Appreciate it, Elita.

Speaker 3

Our next question comes from Timothy A. Rezvan from KeyBanc Capital Markets Inc. Please go ahead. Your line is open.

Speaker 2

Good morning, folks, and thank you for taking our question. 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 two queues has been deferred. It's adding a lot of complexity on understanding the different skew changes we could expect with your production. You said directionally, natural gas will become a bigger part of total production. Can you maybe give a little more detail on that? Do you think that's something you should be including in guidance going forward to sort of help the analyst community? Thank you.

Speaker 1

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. I recognize that we're not the easiest company for you to model. I'll say overall, we anticipate growth in the third quarter and then additional growth in the fourth quarter compared to Q3. We're 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 two oil wells, and one of those was constrained, as we talked about there just a second ago. Now, when you look at the end of Q2 and forward, we've already turned in line two additional oil wells and removed the constraint from the third.

We have four additional turn-in-lines that will happen inside of this quarter, and we anticipate three additional oil tills at the end of Q4. 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 spun wells to, let's say, seven months, you start to see things come online thereafter. Similarly, on the gas side, by the end of Q2, we turned in line five wells, and here in August, we turned in four more, and we have three additional wells that we're targeting being in line before the end of the year.

Speaker 2

Okay. As we look for 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?

Speaker 5

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

Speaker 2

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

Speaker 1

Good, thank you.

Speaker 5

Thank you.

Speaker 3

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

Speaker 4

Yeah. Hey, thanks. Just one follow-up. Those Turtella wells that you all brought online a quarter or so ago, based on the state data, the production looks fairly strong and good. 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+ days that we can see, production is actually holding pretty steady at a much higher rate than we would have anticipated. Any color and commentary on that and how that changes your view or your thoughts on your next gas completions as well?

Speaker 1

I appreciate the compliment there on our well performance. We won't get into specifics on how well it's performing, 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 between how we drill the wells, complete them, space them, etc., for that area so that you'll be able to see continuous, repeatable, predictable gas results there.

Speaker 4

Thanks.

Speaker 3

We have no further questions in queue. I'd like to turn the call back to Zack Arnold for closing remarks.

Speaker 1

All right. 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. Thank you.

Speaker 3

This concludes today's conference call. Thank you for your participation. You may now disconnect.