Infinity Natural Resources, Inc. Class A

Hello everyone, thank you for joining us and welcome to Infinity Natural Resources' second quarter 2026 earnings call. After today's prepared remarks, we will host a question and answer session. If you would like to ask a question, please press star 1 to raise your hand. To withdraw your question, press star 1 again. I will now hand the conference over to Tom Marchetti, Vice President of Investor Relations. Tom? 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 present 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, Tom, 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. As we announced yesterday, David Sproule will be stepping down as our Executive Vice President and Chief Financial Officer. David is one 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 12th, 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 EBITDA 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 second pad during the quarter. 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 three rich gas wells from our Antero acquisition and seven other volatile oil wells. On the operating front, we spotted nine wells, including four volatile oil wells in Ohio, two rich gas wells in Ohio, two 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 profit 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 seven wells. This includes a four-well pad we expect to turn in line in the coming days in the volatile oil window and a three-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 RECS 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 liquid side, we continue to see growing optionality within 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. During 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 REC 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 Ontario acquisition. as well as the increase in overall volumes. Excluding firm transportation costs, GP&T expense was 69 cents per MTFB 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. Our six to seven 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 incompletions 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.