Infinity Natural Resources, Inc. (INR) Earnings Call Transcript

Hello, everyone. Thank you for joining us, and welcome to Infinity Natural Resources' Second Quarter 2026 Earnings Call. [Operator Instructions] I will now hand the conference over to Thomas Marchetti, Vice President of Investor Relations. Thomas, please go ahead.

Thank you, operator. Good morning, and thank you for joining Infinity Natural Resources' Second Quarter 2026 Earnings Conference Call. With me today is Zack Arnold, our President and Chief Executive Officer. In a moment, Zack will present his prepared remarks with a question-and-answer session to follow. An updated investor presentation has been posted to the Investor Relations section 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. Before we begin, I would like to remind everybody 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 differ materially 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 more important disclosure regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Zack.

Thanks, Thomas, and good day, everyone. We're glad to have you with us to review Infinity Natural Resources' second quarter results. It was a busy and productive quarter for our team, and I want to start by thanking everyone at Infinity for the work that went into it. Before we get into our operational and financial results, I'd like to spend some time discussing the changes in our leadership announced yesterday. David Sproule will be stepping down as our Executive Vice President and Chief Financial Officer. David is 1 of the founders of Infinity, and we would all like to thank David for his dedication and passion to Infinity. I would also like to take this time to welcome [ Kerry Bates ] and [ Andrew Judge ] to Infinity Natural Resources. Effective August 12, [ Kerry ] will be assuming the responsibilities as Executive Vice President and Chief Financial Officer, and [ Andrew ] will add a layer of expertise to our existing team as Senior Vice President of Finance. [ Kerry ] has a strong track record of raising capital, leading companies through significant transactions, and building the financial infrastructure to support the kind of growth we expect. [ Andrew ] brings deep in-basin upstream expertise and a proven ability to secure capital, evaluate M&A opportunities, and build strong investor relationships. We are excited to have both executives join our leadership team and, together with our recently expanded Board, continue building the organizational depth and leadership necessary to execute on our long-term strategy. Now let's move on and discuss our results. The second quarter reflected continued execution of our strategy. We delivered strong production growth and our highest quarterly adjusted EBITDAX in company history at $115 million. In addition, we transitioned from integration to active development of our recently acquired Antero assets, bringing our first wells online and beginning drilling operations on a new pad. We have recently completed drilling the second pad and have begun drilling on a third pad. Now more than a full quarter into owning these Ohio Utica assets, we remain very encouraged by the potential to scale the upstream assets with what has been an underutilized midstream system. As we continue integrating these assets, our conviction in their long-term value only continues to grow. Our strategy remains unchanged. We continue to execute the disciplined growth plan we have consistently outlined by scaling production, increasing utilization of our integrated midstream assets, maintaining leading capital efficiency, and lowering controllable costs. At the same time, we continue to evaluate M&A opportunities that strengthen the platform and enhance its long-term cash-generating capacity. Turning to our production and operational execution during the quarter. Net production averaged 348 million cubic feet equivalent per day, a year-over-year growth rate of 75%. We brought a total of 10 wells online in Ohio, including the first 3 rich gas wells from our Antero acquisition and 7 other volatile oil wells. On the operating front, we spudded 9 wells, including 4 volatile oil wells in Ohio, 2 rich gas wells in Ohio, 2 dry gas wells in Pennsylvania, as well as our first deep dry gas Utica well in Pennsylvania. We drilled a vertical pilot on the deep dry gas Utica, collected subsurface data for analysis, and drilled a 9,500-foot lateral. We continue to evaluate the results of the core and data we collected to refine our technical understanding, and we look forward to sharing more with you in the future. In terms of execution, our operations team continues to raise the bar. During the second quarter, we delivered another step change in drilling and completion efficiency, increasing lateral feet drilled per day by 15% compared to our 2025 average while maintaining 100% in-zone geosteering accuracy. We also successfully validated a revised completion design that reduced completion costs by $50 per foot in Guernsey County through higher proppant loading, extended stage spacing, and reducing the number of frac stages. These operational gains improve capital efficiency, accelerate cash flow generation, and reinforce the scalability of our integrated Appalachian development platform. As we look to the third quarter, we expect to turn in line 7 wells. This includes a 4-well pad we expect to turn in line in the coming days in the volatile oil window and a 3-well pad we turned in line in mid-July in our dry gas-weighted Pennsylvania Marcellus acreage. Our diversified portfolio provides the operational flexibility to allocate capital to the highest-return opportunities. Our midstream infrastructure will play a critical role in the reduction of our per-unit costs as we increase system utilization. Since the end of the first quarter, our system utilization has increased approximately 30%, with approximately 70% of our current gross natural gas production flowing through our wholly owned, low-cost system today. We now have approximately 1 Bcf per day of gathering capacity across our integrated midstream system, including roughly 400 million cubic feet per day of capacity in Pennsylvania and 600 million cubic feet per day in Ohio. This system is currently operating at approximately 35% total utilization, providing significant capacity to support future production growth without meaningful incremental infrastructure investment and an opportunity to attract third-party volumes. The strategic value of our midstream system extends well beyond its current utilization. Replicating a comparable footprint today would require substantial capital, long equipment lead times, and significant execution. This infrastructure also allows us to market our production more effectively. Today, our premium market access on the gas side is largely tied to REX Zone 3. As additional in-basin sinks continue to develop, we expect to diversify the markets where we sell our gas products. Our dual-commodity strategy across Ohio and Pennsylvania gives us the flexibility to direct volumes to whichever markets and end customers make the most sense. On the liquids side, we continue to see growing optionality with end customers. And as our volumes scale, and we bring more marketing functions in-house, we believe we have an opportunity to capture additional margins over time. Starting in March, we began taking in-kind the majority of our propane, butane, and pentane products. We've recognized an uplift in propane price realizations over prior periods. Now, getting into more operating details and our financial performance. For the second quarter, our net production averaged 348 million cubic feet equivalent per day. Oil production totaled approximately 12.4 thousand barrels per day for the quarter, up 102% year-over-year. Natural gas production averaged approximately 217 million cubic feet per day, up 73% year-over-year. And NGL production increased 57% year-over-year to approximately 9.5 thousand barrels per day. Natural gas represented 62% of total production, oil 21%, and NGLs 16%. Starting the second quarter financial performance, we generated approximately $171 million in revenues for the quarter and adjusted EBITDAX of $115 million, representing adjusted EBITDAX margins of approximately $3.62 per Mcfe, or roughly double that of our Appalachian peer group average. NYMEX natural gas prices during the period averaged $2.89 per MMBtu. We realized $2.34 per Mcf on natural gas sales, benefiting from our premium market access and transportation portfolio, including sales through the REX Zone 3 market. Our oil price realizations for the period were $85.41 per barrel, with oil differentials of approximately $7.10 per barrel. NGL realizations increased 70% year-over-year to $32.27 per barrel, reflecting a more favorable production composition and stronger NGL pricing, which supported margins during the quarter. On costs, our controllable cash operating costs were down approximately 9% from the second quarter of 2025 and slightly down sequentially from the first quarter of 2026, excluding firm transportation costs. During this quarter, controllable cash costs totaled $1.58 per Mcfe, comprised of $0.32 per Mcfe of LOE, $0.93 per Mcfe of GP&T, $0.20 per Mcfe of recurring cash G&A, $0.07 per Mcfe of midstream operations and maintenance expenses, and $0.06 per Mcfe of production taxes. Let me take a minute to discuss our GP&T specifically. Our reported GP&T expense increased during the quarter, primarily due to the inclusion of firm transportation costs related to the REX Zone 3 contract that we assumed in the Antero acquisition, as well as the increase in overall volumes. Excluding firm transportation costs, GP&T expense was $0.69 per Mcfe in the second quarter, reflecting a decline in operating costs quarter-over-quarter. The other factor that contributed to our costs was an increase in liquids-weighted development. As our production mix shifted toward liquids, we earned more revenue per unit. But liquids require more processing and fractionation than dry gas. So a modest piece of the increase reflects real incremental costs that comes with a more valuable production mix and margin uplift. Looking at our full controllable cost stack, including LOE, GP&T, cash G&A, and production taxes, we expect this to decline structurally as volumes grow across our platform and the company increases its development of both the acquired Antero properties and our dry gas assets in Pennsylvania, with those volumes flowing through our own midstream system. During the second quarter, capital expenditures incurred were approximately $137 million, which included $129 million on development activities and $8 million on land activities. Our strategy is to build an integrated Appalachian platform that increases in value over time. Rather than viewing each acquisition as a standalone transaction, we view each investment as another building block that strengthens the overall platform. Additional inventory extends development opportunities, producing assets increase scale, and midstream infrastructure lowers costs, while creating new commercial opportunities. Together, these assets improve capital efficiency, strengthen our cash-generating capability, and create long-term value for our shareholders. Our capital allocation philosophy is straightforward. Capital follows returns, not commodities. We continue to invest in organic leasing and acquisitions, upstream development, and midstream infrastructure, while maintaining the flexibility to allocate capital to the highest-return opportunities as market conditions evolve. The 6- to 7-month development cycle time provides the operational flexibility to adjust activity, optimize development sequencing, and enhance returns as conditions change. Our hedging philosophy begins at the project level. We evaluate the expected economics of each pad and use hedges to lock in those returns and provide greater visibility into our cash flows. For the remainder of 2026, we are 81% hedged on natural gas and 70% hedged on our total volumes based upon the midpoint of our guidance. This approach allows us to remain disciplined regardless of the commodity environment. Every investment is evaluated against our return thresholds and its ability to strengthen the platform. As the platform continues to scale, we expect higher infrastructure utilization, lower unit costs, and strong margins to further enhance our long-term cash-generating capability. Finally, on guidance. For the full year 2026, we are reaffirming our prior guidance and continue to expect net production to average between 345 and 375 million cubic feet equivalent per day, representing growth of approximately 70% year-over-year. Similarly, our expectations for development capital expenditures, which are a combination of drilling and completions and midstream expenditures, remain in the range of $450 million and $500 million. To wrap up, the second quarter reinforced the strength of our integrated Appalachian platform with a company record for adjusted EBITDAX and best-in-basin adjusted EBITDAX margins. The recent changes to our leadership only strengthen our capabilities as we continue to execute on our strategy focused on production growth and disciplined capital allocation. Operator, please open the line for questions.

[Operator Instructions] Your first question comes from the line of Timothy Rezvan with KeyBank Capital Markets. Your line is open. Please go ahead.

I want to start, Zack, on Slide 11. We appreciate the table you all provide with TIL timing across the asset base. We can see there's a clear oilier skew to summer, fall TILs, and then some gassier TILs in the fourth quarter. So I know you made the pivot to oil this year. Is the timing of this sort of intentional to capture the seasonality of gas prices? And how are you and the Board thinking about this as we go to '27 with the timing of oil and gas TILs?

Great question, Tim. Thank you. I think starting and speaking most clearly, we're trying to not be a company that chases the whims of a commodity price. So we're giving Slide 11 because I think it really helps analysts model what's coming online when. And I'm glad that you appreciate that slide. I think what we see is when we have a strip that we like and we decide to execute a project, we can execute on hedges to de-risk that. So I think about it less of trying to time a gas turn-in-line with optionality and more of this is a function of our typical rig cadence matched with thoughtful hedging and the little bit of the reorganization of completions we did in the middle of the year to bring the oil fracs ahead of the gas fracs. So I think the timing should shape up well, but it isn't us trying to seek, you know, a proper time to turn a gas well on because of a theoretical gas price.

Okay, that's fair. As my follow-up, I wanted to try to respectfully ask about the executive changes that were announced last night. I know you're limited in what you can say, but can you maybe give the Board's perspective about the specific skills that the new hires are going to bring and why you think that makes Infinity better having them on board? Thank you.

Sure. So first of all, I want to thank David for all of his hard work, his dedication, and his friendship over the last 10 years. This is the right hire for us at the right time for this company. [ Kerry ] has decades of public company experience to help with our growth trajectory. And we're very excited about that skill set that he brings to Infinity. And when we combine that with [ Andrew ]'s capabilities, we think, along with the Board, that we are incredibly well-positioned for the scale growth that we are seeking.

Your next question comes from the line of Michael Scialla with Stephens. Your line is open. Please go ahead.

Zack, you gave us some capital efficiency numbers year-over-year. I wanted to see more specifically if you had anything on the new wells that you've now completed on the Antero acquisition properties, if anything you can say relative to how you're completing those wells cost-wise relative to the prior operator, and have you seen enough well performance there to say anything about the productivity of those wells?

Sure. I'll start by saying every day we spend with this asset, we're more and more excited about it. And also, it's still early days in our development philosophy on the asset. So everything that we're seeing is very new and fresh. We'll communicate more details about some of these synergies and efficiencies that we see in the coming quarters, but I can start by saying the well performance from the first 3 wells that came online this quarter is, we're very, very happy with them. They're meeting or exceeding our expectations, and our underwriting cases are developing. With a rig, and moving the rig around the field has been quite smooth and quite efficient. Really proud of the team where we landed on our first pad with the drilling rig. Very shortly after close, drilled those 3 wells and have moved it to another pad. So this is, we're starting to see the full benefits of us having 1 rig in 1 field, moving it around. And you have to give a shout-out to the land team who took an asset that was not necessarily prepared for full-field development like we are now, and continuing to give us wells to develop in the order in which we need them for the rig. So really happy with everybody's execution there. I think we are seeing a difference in our completion philosophy. We're pumping about 1,000 pounds of sand more than Antero had per foot, about 1,000 pounds of sand per foot more than Antero. And I think that's going to yield over time fantastic results. And I think we've got some benefits that we're going to be able to bring on some of the top-hole sections of drilling that if we give our drilling team a couple of more quarters, we're really going to be able to see some days come off of the underwritten drilling case too.

That's good. And it sounds like you're going to update your, I think you had an annual synergy target at $25 million. Are we going to get an update on that down the road here?

Yes, I think it's too early to speak in a lot of detail, but I think first and foremost, there's a lot of synergies that come from the REX contract that we bought with the deal, helping us get our volumes from our legacy pads to a premium market. And then we have maybe just a little bit of a highlight that we'll share more details on in the coming quarters. But the pad that the drilling rig is sitting on now is going to be a combination of 2 pads from the old drilling plan, the Antero drilling plan. So that's allowed us to eliminate pad construction, road construction, and pipeline construction, and put these wells that we're drilling onto an existing pad and lever what's already been built there. So really excited about that, and not going to talk numbers today, but you do that a few times and you really work through that $25 million in synergies quickly.

Sounds good. I wanted to ask on the, you mentioned on NGLs you're seeing an uplift there. I think you were at one point looking at potentially renegotiating your MPLX contract. Anything you can say there?

No, nothing I can say right now about that other than to just say we've got the contracts in place that are necessary for us to move our volumes. And as contracts need renewed, we'll negotiate on those. And we have a longstanding relationship with MPLX and excited to work with them as we move our volumes.

Your next question comes from the line of Paul Diamond with Citi. Your line is open. Please go ahead.

You talked about recent improvements in the frac design. I guess in the near term, what do you see kind of the next opportunity beyond the recent tweaks? Is it in lateral length? Is it in proppant loading? I guess where is the next kind of step change you see in the near term?

Thanks for the question, Paul. I think first and foremost, we were excited about applying the completion design that we sort of mastered in Carroll County down in Guernsey and Northwestern Noble in the volatile oil window. We think that allows us to put more sand per foot with a little bit fewer stage count per well, which allows us to be maximized on our efficiencies and pumping hours per day, which is really what we measure on. Looking at stages per day doesn't necessarily compare you apples-to-apples. But when we can focus on hours pumped per day, that really lets us measure our efficiency. So I think always completions is a spot where we focus on seeking efficiencies, and we'll continue to do that. I think we also see opportunities on the drilling side where we continue to optimize bottom-hole assemblies and really maximizing the amount of footage we can drill in a day to help us cut a day or 2 off of pro forma drilling, which makes a big difference in each project and lets us do more within a calendar year.

Got it. Understood. And then talking about the, you guys talked about some potential third-party utilizations. I guess, can you give any detail on a potential timeline or kind of opportunity set you see there for ramping the third-party side of that equation?

Yes, no, thank you for that question. And I want to say that today and for the near future, our midstream revenues from third parties are going to be small. And I think for us, we're focused on utilizing that midstream system for our upstream development in the near term. It lets us have very low breakevens, very low operating costs and LOE. So we love the midstream system for our own operated assets. The third-party revenues are going to show up first in third-party interest inside the units we develop. And near term, because of the way our land team is putting together high working interest units, we really don't see those manifest in the near-term development of the Antero assets. Those are effectively 100% working interest units. We do think that there's opportunities, there's interest from third parties, and we'll continue to explore that. But for now, I think let's focus on using the midstream for our own gathering and our own cost controls, and we'll let the third-party revenues show up when they're available.

Understood.