管理層發言
Hello, everyone. Thank you for joining us, and welcome to Infinity Natural Resources First Quarter 2026 Earnings Call. I will now hand the call over to Mr. Tom Marchetti, Vice President of Investor Relations. Please go ahead, sir.
Thank you, operator. Good morning, and thank you for joining the Infinity Natural Resources First Quarter 2026 Earnings Conference Call. With me today are Zack Arnold, our President and Chief Executive Officer; and David Sproule, our 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 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 everyone that today's call may contain forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied. 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 those forward-looking statements. Please review our earnings release and risk factors discussed in our SEC filings. We will also be referring to certain non-GAAP financial measures. Please reference our earnings release and investor presentation for important disclosures regarding such measures, including definitions and reconciliations to the most comparable GAAP financial measures. With that, I will turn the call over to Zack.
Thank you, Tom, and good morning. We appreciate everyone joining us today to review Infinity Natural Resources first quarter results. The first quarter was pivotal for Infinity. We successfully closed the Antero, Ohio Utica acquisition in late February, our largest transaction to date, and added working interest in our Pennsylvania asset through the Chase acquisition. These acquisitions immediately increase our scale with our operated well count increasing from 154 to 395 and our midstream system expanding to over 250 miles of gathering and water pipelines, positioning Infinity for disciplined growth through the end of the decade. Importantly, we did so while preserving the quality of our balance sheet through strategic financing, including the issuance of perpetual preferred securities and senior notes. Since closing these transactions, our teams have been focused on integrating the assets into our operational platform. This includes onboarding personnel, evaluating the new inventory, and identifying opportunities to optimize operations across the acreage and associated infrastructure. The more time we spend with the Antero assets, the more excited we become about the opportunity, especially the midstream infrastructure, which we will discuss in more detail in a few minutes. Before that, let me review production and operating highlights from the first quarter. Net production averaged 299 million cubic feet equivalent of gas per day, a year-over-year growth rate of 88%. We turned to sales four wells in the volatile oil window with 53,000 lateral feet — two in early February and two in mid-March. On the operating front, we added a second frac crew and a second rig during the quarter, and we stimulated 11 wells and drilled 10 wells to total depth, which is a company record. One of the frac crews was deployed to the assets we acquired from Antero approximately 30 days after closing near the end of the first quarter and we expect to turn those first three wells from the acquisition to sales during the second quarter. We've had one rig on legacy Infinity volatile oil window assets and one rig on legacy Infinity natural gas assets since January, and we intend to move a rig onto the newly acquired Antero asset later this quarter. As we have previously discussed, our plan for the balance of 2026 is to run one dedicated rig on legacy Infinity assets, drilling both volatile oil and dry gas wells, and one rig on the newly acquired assets. As of today, we have accelerated completion activity in our volatile oil window to capture stronger near-term returns, which includes pulling four oil-weighted wells into the second quarter from later, with mostly unhedged barrels. That said, we retain the flexibility, as always, to quickly pivot between commodities and we'll lean harder into the natural gas market if conditions warrant the shift. We continue to focus on longer laterals. During the first quarter, the average lateral length turned in-line was over 13,000 lateral feet. We benefit from efficient cycle times with multi-well projects continuing to reach first production within six to seven months, supporting faster capital recycling and improved returns. As an example, we started drilling on a four-well, 55,000 lateral foot oil-weighted pad in November, and we expect to turn in those wells in the coming days. Coming back to our newly acquired midstream infrastructure: in our minds, the scale and versatility of this unique system is vastly underappreciated with 140 miles of gathering lines, 90 miles of water lines, six compressor stations and nearly 80,000 horsepower. This is a turnkey system with no lead time or bottlenecks that would likely take years to replicate. We have retained nearly all the field employees associated with these assets and hired additional senior leadership for Midstream, including a Vice President of Midstream. The continuity and deep expertise of our midstream bench is truly invaluable. We are excited by the value that we can unlock from the system. To put it bluntly, we believe it is poised to become a meaningful contributor to future results as we are one of the limited number of operators in the Appalachian Basin with owned midstream infrastructure. Currently, the system is underutilized, operating at less than one quarter of its currently available capacity, providing significant runway to support not only our own development but also third-party volumes. We received third-party volumes on the system for the first time during the first quarter, and we will be focused on increasing third-party volumes on the system. As we move through the year, we expect to drive a meaningful ramp in throughput that will contribute to our financial results. This infrastructure also provides a significant structural cost advantage as we leverage existing pads and pipeline connections, significantly reducing or eliminating the need for incremental midstream capital on new development. As of today, approximately 75% of Infinity's natural gas volumes are flowing through our owned midstream system, and we expect that to increase as we ramp development. This system creates a strategic advantage for us that we expect to drive improved margins and lower breakevens over time. We'll share more over time as we continue to operate the asset sets. I will now spend a few minutes on the macro. We remain constructive on the longer-term outlook for both liquids and natural gas. Oil and liquids markets in Appalachia remained strong with a combination of domestic and international demand from refining and chemicals driving a favorable pricing environment. Beginning in April, we have increased our take-in-kind NGL volumes, which provides us greater control and optimization of the realized pricing specific to propane, butane and pentane. For natural gas, we see a clear cadence of demand growth with near-term strength driven by LNG exports, continued momentum from gas-fired power generation in-basin, data centers, and longer-term expansion tied to industrial development. As these demand drivers scale, we expect regional gas differentials to tighten alongside broader market growth. Given our outlook for oil and liquids, we have leveraged the flexibility of our platform to adjust our completion schedule and accelerate facilities construction to pull forward oil-weighted wells into the second quarter and to capture stronger price realizations. We will continue to evaluate our development plans across the portfolio with a focus on directing capital towards the highest return projects. Against this backdrop, here's where our plan stands for the second quarter. As I touched on earlier, we expect to turn in-line a four-well pad in the volatile oil window in the coming days, representing 55,000 lateral feet. We also expect to bring to market our first barrels from the Antero acquisition later this quarter, a three-well pad in our rich gas area with 53,000 lateral feet. That's a total of seven wells turned in-line and 109,000 lateral feet during the second quarter. With that, I will turn the call over to David to review our financial results and outlook.
Thank you, Zack, and good morning. Our financial and operational results for the first quarter reflect continued execution by our team. We anticipate that our production will increase each quarter throughout the remainder of the year. During the first quarter, our net production averaged 299 MMcfe per day. We expect the first quarter to be our lowest production total for the calendar year. In terms of the components of production, oil production totaled approximately 9,600 barrels per day for the quarter, up 16% year-over-year. Natural gas production averaged 195 MMcfe per day, up 169% year-over-year. And NGL production increased 25% year-over-year to 7,800 barrels per day. Natural gas represented 65% of our total production, with oil being 19% and NGLs being 16%. Turning to financial performance: we generated approximately $155 million in revenues for the quarter and adjusted EBITDA of $97 million, representing adjusted EBITDA margins of approximately $3.61 per Mcfe, which we believe is best-in-class in the Appalachian Basin. The company saw improved natural gas prices during the period that averaged $4.86 per MMBtu. Our regional differentials remained steady at $0.69 per MMBtu, reflecting a greater weighting towards a lower Btu content in our gas stream. Oil price realizations for the period were $65.77 per barrel. First quarter oil differentials tightened to slightly less than $7 per barrel during the period. We anticipate our oil differentials to remain consistent, around $7 to $8 per barrel for the second quarter. NGL realizations were strong during the quarter, supported by better NGL composition, firm pricing and export-driven demand, contributing to the overall strength of our revenues and reinforcing the value of liquids-weighted development across our portfolio. Turning to costs: our controllable cash operating costs during the quarter totaled $1.43 per Mcfe. These costs reflected the impact of an extremely cold winter, which drove higher rental costs and snow removal as well as true-ups for annual compensation. On a year-over-year basis, controllable cash operating costs declined approximately 18%, a reflection of the benefits of scale and improved operating leverage. As volumes grow across our Appalachian platform, and we increase the utilization of our owned midstream infrastructure, we expect our overall cost structure to improve further. During the first quarter, capital expenditures incurred were approximately $123 million, which included $112 million on development activities and $11 million on land activities. Our capital allocation strategy remains disciplined and focused on long-term value creation. During the quarter, we deployed completion crews to prioritize development in our volatile oil window to capture the strength of near-term oil markets. Our stimulation activities are expected to shift back toward natural gas towards the back half of this year. We continue to prioritize high return opportunities across our Utica and Marcellus assets, selectively expand our inventory through accretive acquisitions and organic leasing, and maintain a strong balance sheet with ample financial flexibility. During the quarter, we raised $550 million in senior notes and $350 million of preferred equity. The transactions enabled us to pay down all outstanding debt under our revolving credit facility and increase our liquidity position while expanding our investor base with institutional credit investors and premier energy investors. We are well positioned with financial flexibility to execute our business plan. At quarter end, we had net debt of approximately $477 million and total liquidity of approximately $929 million. Our pro forma net leverage on an LTM basis was 1.3 turns during the period. We would anticipate our net leverage ratio to decline during the course of the calendar year towards our target leverage level. For 2026, we continue to expect net production to average between 345 and 375 MMcfe per day, representing growth of approximately 70% year-over-year, with gas production of approximately 235 to 255 MMcfe per day and oil and liquids production of 18,000 to 20,000 barrels per day. Development capital expenditures, which are a combination of drilling and completions and midstream capital expenditures, are expected to range between $450 million and $500 million. With that, I will turn the call back to Zack for closing remarks.
Thank you, David. As we move through 2026, we are advancing development across our assets with a continued focus on consistent operational execution, strong financial returns and long-term shareholder value creation. Across the Ohio Utica and Pennsylvania Marcellus and Utica, our portfolio offers a deep inventory of high-quality development opportunities supported by our owned midstream system. We are particularly excited about the opportunity within our midstream platform where increasing volumes flowing through the system are not only driving incremental efficiencies and margin benefits but also positioning midstream to become a more meaningful contributor to earnings and cash flow over time. We will continue to evaluate complementary acquisitions that strengthen and expand our integrated Appalachian business while also assessing development timing and potential hedging opportunities to optimize returns in the current commodity price environment. Operator, please open the line for questions.
分析師問答
Your first question comes from the line of Scott Hanold with RBC Capital Markets. ng through the system are not only driving incremental efficiencies and margin benefits but also positioning midstream to become a more meaningful contributor to earnings and cash flow over time. We will continue to evaluate complementary acquisitions that strengthen and expand our integrated Appalachian business while also assessing development timing and potential hedging opportunities to optimize returns in the current commodity price environment. Operator, please open the line for questions.
Zack and team. Look, I mean, obviously, as your business strategy has been, you're very flexible to change your activity pace with the commodity and the macro and pulling forward some more oil stuff. Can you just give us a sense of what should we expect on some of the cadence on some of that oil production? Obviously, one or two wells can make a big difference for you all. But seems like should we see a bigger step-up in oil? And can you kind of talk about how the base decline rate works right now with you all and what to expect in the next quarter or two?
Great question, Scott. This is Zack. I'll take the first part of that, and Dave can kind of chime in — we'll tag team it. But I think, first and foremost, I'll address your decline question. We continuously are pleased and proud of our PDP and our new well performance. I think we've had very nice results and we continue to demonstrate that. As we exited last year, we had a really big ramp into the end of the year. It was driven by a lot of terminal lines in late third quarter and early fourth quarter, so that saw a big ramp there. The wells that we talked about turning in-line in this quarter are really going to manifest more in second quarter production as they came in line late in the quarter and especially when you factor in effective contributing days at target rates. So I think you'll start to see the first quarter development really showing in second quarter as well as the second quarter wells beginning to come in-line. When we talked last time about what changes we wanted to make based on commodities, I think what we've really tried to do is not blow up the development schedule we put in place, but look for ways to pull barrels forward. We're really proud of what the team has done. We'll have some turn-ins coming online in June that weren't anticipated to be due, so that's meaningful as we bring those barrels in. That will put them at full rate in July ahead of when we had originally budgeted. Because of that acceleration, that gives us a lot of exposure to unhedged barrels there. I'm sorry if I missed anything else in your question; do you want to add anything back in?
Your next question comes from the line of Tim Rezvan with KeyBanc Capital Markets.
Scott sort of stole our first one on the oil, so I appreciate the outlook there. But I did notice you have a 10,000-foot Utica test base this quarter. I know there's been some — it seems like it may be underway soon or it's finally going to happen here. There's no completion schedule or timeline this year; I guess maybe it's more of an early 2027 event. But can you talk kind of about your predrill expectations for this well? Do you view this like a development well? Is it more like a science well? Is there anything specific you're kind of looking to confirm here and any idea on when you plan to turn it to sales would be helpful.
Yes. All good questions, Tim. And it's a question that we get quarter-to-quarter. I think what we can say right now is we continue to watch offset operations and are monitoring what our peers are doing. We do have a rig on that location, and it's going to be focused on the science portion of this project. We'll drill a vertical pilot and collect some data there that we'll analyze. You are right in noticing that we don't intend to drill this well horizontally or complete it in this calendar year. This is really step one of a evaluation. So we'll go collect some science and spend some time observing it and measuring the things that we need to, so we can properly plan our development there. But as I think we've said before, it's an exciting well for everyone else to watch, but it's one out of the 40-plus that we have this year. So we're really excited to focus our capital predominantly on projects that have clearly defined returns and a long track record of success.
Okay. Great. We'll stay tuned, I guess, for updates on that. And just want to follow up. I know David gets this question every quarter, but just kind of big picture on M&A trends. We see the same thing you all see with leverage kind of going to or below one turn by the end of the year. And I know you're integrating Antero, but you're pretty clearly a growth-focused company. So just kind of curious what your capacity for incremental M&A, like larger pieces, is at this point and what we're seeing in the market.
Yes. I think — thanks for the question, Tim. This is Dave. I think for us, one of the things that we were very cognizant of is both integrating and positioning the company for continued opportunity sets. We are highly active in that environment, and we are highly selective in that environment also. So we are very well positioned to capitalize on assets that we see that fit our portfolio, and so we will continue to evaluate those as they come across our desk. But we are very selective in that. Obviously, we've integrated a very big asset here. That integration has gone extremely well and positions us not just to execute on our development plan that we have in front of us, but positions us to have the flexibility to evaluate other things as they come through.
Your next question comes from the line of Nicholas Pope with ROTH Capital.
I would like to talk a little bit more about the integration of the Antero assets. Obviously, they haven't seen a lot of drilling in the past few years before you guys acquired them. And just as you kind of — I think we're three months, almost three months, into owning the asset, curious as you look at the existing producing base what the opportunity set looks like, low-hanging fruit to optimize production on that asset? And maybe how that might flow through LOE in the near term as you look at that opportunity set, if anything changes. How are you looking at that asset as you've got it in-house?
No, that's a great question. Thank you, Nicholas. This is Zack. I'll take a first crack at it. I think, first and foremost, we are identifying some low-hanging fruit and things that our production engineering team can focus on. It's kind of small-ball stuff where you're working on bottom hole assemblies and plunger lifts and some things that are just really optimizing the existing legacy production there, but still it's worth doing, and we're excited about that, and our team is focused on that. When you think about LOE impacts, we're still getting our mind around the optimization of these wells that we can do. I think owning our midstream is, first and foremost, critical, but one spot where we see some exciting near-term activity to help that is with reusing of water. With the increased completion activities on these assets and our legacy assets in Wolf Run, that gives us a better capability to reuse water from the field, and that should have a net positive impact on some of our operating costs.
And I guess maybe stepping back a little further, like the broader LOE for the company — how do you anticipate that shaping over the remainder of 2026 as you look at these assets?
Sure. So I think when you look at the first quarter, our LOE ticked up to about $0.33 per Mcfe. I think that's more of a reflection of the very, very harsh winter that we had in this part of the country. If you look year-over-year, our costs have gone down significantly. We would anticipate those costs to continue to decline along the trend line in 2026. With regards to the Antero integration and the impacts therein: because of our ownership of the midstream assets, we start with a significant head start because our gathering and compression charges are lower with regards to the development of those assets. So you should anticipate over the course of this year our overall cost structure to continue to decline, both from an impact from volumetric growth as well as from integration where the Antero assets have a lower cost structure than our assets in Carroll County or in legacy Guernsey County.
Your next question comes from the line of Michael Scialla with Stephens.
You were able to add some acreage during the quarter. I just want to see what the opportunity set looks like there. Is it any different now with the Antero acquisition? And maybe how the cost of land has changed over the past year. Can you give any sense there and however you want to break down in terms of cost per new drilling location, maybe difference between Ohio and Pennsylvania, if you could.
Yes, we've been really proud of what our team has done to continue to add acres, especially in a quarter that was overshadowed by closing of two deals. The mating acres, I think, was a testament to their ability to execute two jobs at once. So very proud of that. We've seen nice opportunities to add acres both inside and outside of our units in both Ohio and in Pennsylvania. The new Antero acquisition gave our land department more units to focus on and has helped us be thoughtful with cost allocation and making sure that we're spending our dollars into acres that will get developed at a cost that we're happy with. As a reminder, in Ohio, once you reach a threshold for statutory unitization, that puts you in a good position from a leasing perspective to execute on the development plan in front of you. I like that opportunity. I won't give specific lease per acre numbers, but our team is always focused on getting the best value that they can, understanding where APIs fall into our inventory and being thoughtful with dedicating dollars and really focused on leases that have tight cycle times for us, putting them in front of the drill bit and in units that we plan to drill so that we can get the return on those lease spends very quickly.
Appreciate that, Zack. I know you guys had talked about potentially pivoting at some point to generate positive free cash flow. Maybe your latest thoughts there on what the timing of that might look like.
I mean, I think in terms of our overall development program and the guidance that we provided, obviously this is a fairly capital-intensive year. We've discussed priming the pump with regards to the Antero acquisition that we've closed upon. But we would anticipate trending down over the next five years to be consistent with that of our offset peers while still having outsized growth. So we would anticipate our CapEx as a percent of EBITDA to be lower this year than last year, and we would anticipate that trend to continue into the coming years.
Your next question comes from the line of Paul Diamond with Citi. program and the guidance that we provided, obviously this is a fairly capital-intensive year. We've discussed priming the pump with regards to the Antero acquisition that we've closed upon. But we would anticipate trending down over the next five years to be consistent with that of our offset peers while still having outsized growth. So we would anticipate our CapEx as a percent of EBITDA to be lower this year than last year, and we would anticipate that trend to continue into the coming years.
Just wanted a quick one to touch on. You guys talked about shifting activity more towards dry gas in the latter half of the year. From a production perspective, how should we think about that cadence-wise? Is that a pretty midyear progression? Or would we still expect to see those kind of step-change moves?
In terms of step changes of the production, Paul, I would expect that we will still exhibit heightened growth in each of our hydrocarbons every quarter going forward. I think the cadence of activity would lend itself to have a really heightened third quarter with regard to turn-ins relative to the overall year. I do think that adding natural gas towards the middle to end of the year does have an impact on our overall natural gas volumes. But again, it's relative to the other components and the time frame of it being online. So I wouldn't necessarily expect a single, dramatic step; it's a question of degree. We would anticipate each quarter to be higher than the last as you shape the development of the assets that we have. So I'm probably not going to give you the exact answer you want there, but I would tell you that we would anticipate our fourth quarter to be our highest production quarter for the year.
Got it. Understood. And then one more strategy question: obviously, you guys have been growing both organically and via acquisition. How do you see that growth rate in 2027 and beyond? Is there a point where you see that slowing or leveling off — a target rate where you get to the next level where the strategy changes? Should we expect growth to remain?
Yes. I think a lot of big numbers and small-number aspects: you can't continue to grow at a 70% or 80% clip indefinitely. For us, as we think about 2027 and beyond — obviously, we haven't provided guidance on that — it's fair to say that our production growth will still be relatively elevated compared to our peers, but we would start to expect to trend down as a percent of reinvestment over that time period.
Your next question comes from the line of Scott Hanold with RBC Capital Markets.
Sorry, I missed you before when I asked my question. But my follow-up was on the infrastructure and the infrastructure utilization. You talk about it being underutilized and an opportunity to continue to grow — can you speak to how much of the capacity you think you'll reserve for third parties versus keeping for your own production growth? And what kind of third-party revenue growth could that generate over the coming quarters?
Yes, I'll take the first part of that question and handle that. First and foremost, when we look at these assets, we're incredibly impressed with how things have been positioned walking across some of the compressor stations and realizing just the infrastructure that's in place there and how little utilized it is today. That gives us a lot of excitement about ways that we can continue to grow the use of that system. When we think about third-party volumes and our own volumes, we're always going to prioritize our own volumes first. I think as we begin to think about ways that third-party volumes materialize, most of those initially are going to materialize just through the units that we develop and having other operators inside of our units and other interests that we don't have lease inside of units. As you see that, that will come naturally with our own development profile. So I think we won't put ourselves in a position in which the infrastructure is bottlenecked because of other competing objectives that we have. Our ability to leverage the expertise of some of the field staff we brought in as well as some of the senior leadership that we're adding to the team really allow us to look closely from an engineering and a business perspective, making sure that the system that we have today continues to be optimized for however we add volumes to it through our own drill bit or third-party volumes.
Yes. I would just add, Scott, that it's a 600 million cubic feet per day pipeline. We're actively developing in that area, as Zack's highlighting, but we are highly incentivized to fill that pipe. And so we will push to do so.
When you set up these contracts with third parties, are they more like spot month-to-month volumes? Or are you locking in some longer-term contracts with them?
I think at this stage we'll probably stay a little muted on that. It's case-by-case on a lot of the opportunity sets that we see. We'll probably talk a little bit more about that later in the year as we ramp things up. Right now, it's really small numbers, so it's not that impactful; it's truly just opportunities that we're making sure we're thoughtful about exploiting.
There are no further questions at this time. I will now turn the call back over to Zack for closing remarks. Please go ahead.
Thank you very much for joining us for the call today. We appreciate your continued interest in the company, and we look forward to sharing additional results with you soon. Operator, back to you.
Thank you. This concludes today's call. Thank you for attending. You may now disconnect.