CNX Resources Corporation (NYSE:CNX) Q3 2025 Earnings Call Transcript

CNX Resources Corporation (NYSE:CNX) Q3 2025 Earnings Call Transcript October 30, 2025

CNX Resources Corporation beats earnings expectations. Reported EPS is $0.49, expectations were $0.37.

Operator: Good morning, and welcome to the CNX Resources Third Quarter 2025 Q&A Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Tyler Lewis. Please go ahead.

Tyler Lewis: Thanks, and good morning, everybody. Welcome to CNX’s Third Quarter Q&A Conference Call. Today, we will be answering questions related to our third quarter results. This morning, we posted to our Investor Relations website an updated slide presentation and detailed third quarter earnings release data, such as quarterly E&P data, financial statements and non-GAAP reconciliations, which can be found in a document titled 3Q 2025 Earnings Results and Supplemental Information of CNX Resources. Also, we posted to our Investor Relations website our prepared remarks for the quarter, which we hope everyone had a chance to read before the call as the call today will be used exclusively for Q&A. With me today for Q&A are Nick DeIuliis, our Chief Executive Officer; Alan Shepard, our President and Chief Financial Officer; and Navneet Behl, our Chief Operating Officer.

Please note that the company’s remarks made during this call, including answers to questions, include forward-looking statements, which are subject to various risks and uncertainties. These statements are not guarantees of future performance, and our actual results may differ materially as a result of many factors. A discussion of risks and uncertainties related to those factors and CNX’s business is contained in its filings with the Securities and Exchange Commission and in the release issued today. With that, thank you for joining us this morning. And operator, can you please open the call up for Q&A at this time?

Q&A Session

Operator: [Operator Instructions] Our first question comes from Zach Parham from JPMorgan.

Zachary Parham: First, Nick, congrats and good luck in your retirement. And Alan, congrats on your new role. First off, I just wanted to ask on the buyback. You had a sizable buyback during 3Q. It was the highest since, I think, 4Q ’22. Can you talk about what drove that uptick in buybacks and how you think about the pace of the buyback going forward?

Alan Shepard: Yes. I think the primary driver was a significant free cash flow generator in terms of what we were able to do for the quarter. Our underlying process for evaluating whether or not we’re doing buybacks versus other capital allocation opportunities hasn’t changed. We continue to view the business valuation very attractive relative to its intrinsic value.

Zachary Parham: And then my follow-up, just wanted to ask on the Utica acquisition that you made on the Apex acreage. Could you give us a little more color there? Do you now have Utica rights across the position? If not, are there — are you looking to make other acquisitions where you could get more Utica rights on that acreage?

Alan Shepard: Yes. If you recall, when we did that acquisition, there was about 30,000 Marcellus acres kind of the footprint for the whole asset, and it came with about 8,000 Utica rights. So what that transaction represents is we really went out there and got the remaining unleased Utica rights that underlies that footprint for Apex. And now we’re able to go back in and leverage all that infrastructure kind of like we envisioned when we did the acquisition.

Operator: The next question comes from Leo Mariani from ROTH.

Leo Mariani: I wanted to see if there’s any type of update on new tech here. Specifically, I was just curious if there’s any update on kind of the oilfield service auto business, perhaps the CNG kind of LNG business and/or just status of 45Z as you guys see it?

Alan Shepard: Yes. So let’s start with 45Z. So we’re still in the period where we’re waiting for the notice of final rule-making on 45Z, and we expect that before the end of the year. And then there’ll be a comment period and a finalization of that rule, hopefully in the early first half of 2026. All that’s subject to the government reopening and things like that. But once we have that, the expectation is that the guidance we provided last quarter on 45Z, that $30 million a year run rate will be sort of confirmed with that guidance. In terms of oilfield services, we have outsourced sort of the operational part of that to our partner on that, and they’re continuing to make progress in rolling out those different technologies, but nothing material in sort of the current quarter for ’26 as of yet.

Leo Mariani: Okay. And just in terms of the plans as we roll into next year, just at a high level, it sounds like the company still wants to stay in maintenance mode. Should we expect production is not a whole lot different in ’26? And would that be similar for spending as well? How are you guys thinking about that?

Alan Shepard: Yes. I mean we’ll give you the full detail on the guidance when we get to January. But generally, I would expect to see maintenance mode, right? We’re still going into winter full storage, and we’ll see what kind of weather we get this winter. And we need to see some of these longer-term calls on gas develop before you’d be thinking about doing anything other than that.

Leo Mariani: Okay. That makes sense. And just on M&A, obviously, you guys sold a little asset, bought another asset, seems kind of longer-term neutral on cash. But just what’s the company’s appetite in general for deals? Do you see other things that you’d like to pick up in Appalachia and perhaps there’s other Utica deals out there that you guys would like to consider?

Alan Shepard: Yes. We look at everything that comes to market, but our threshold is acquiring ourselves, right? So unless there’s an opportunity that outcompetes that opportunity, you won’t see us do anything, right? So that’s sort of how we think about it, but we’re certainly open to anything if the math works.

Operator: The next question comes from Noah Hungness from Bank of America.

Noah Hungness: Just for my first question here, I was just hoping you could kind of unpack some of the moving pieces on your free cash flow guidance. Even when you take out the asset — the additional asset sales, it looks like free cash flow guide is roughly flat to where it was before, even though the adjusted EBITDAX guide moved down and CapEx moved up. I was just hoping to unpack some of the moving parts there.

Alan Shepard: Yes. So the way to think about that is our free cash flow guidance includes all working capital adjustments, right? So if you try to take just EBITDA and CapEx, you got to account for sort of fluctuations in AR and AP. I mean we give you a sort of rough number to target for, and we try not to move that number around a bunch. But you’re going to see movements like you see here where we’re refining guidance throughout the year. But we’re still confident we’ll be at kind of the range we guided to, $575 million pre-asset sale number.

Noah Hungness: Great. That makes sense. And then on the Utica acquisition here in Pennsylvania, could you maybe talk about — are there any requirements for drilling on that acreage next year? Or is there any acreage that may be expiring near term that you’ll want to drill on to hold it?

Alan Shepard: Yes. So I mean, we plan to develop the field. Obviously, that’s part of the underwriting case for making the investment. The exact timing of that development, I’m not going to get into at this point, but you’ll see that fold into our development plan in the years ahead.

Operator: The next question comes from Michael Scialla from Stephens.

Michael Scialla: I had a couple of questions on the Utica. I guess as you think about next year’s plan, is there any thought about trying to delineate the play any more with wells maybe further north or further south? Or do you plan to stay kind of in that area that you’ve been developing so far?

Alan Shepard: Yes. I think the plan for next year is really just focused on sort of the operational side of it, right? Nav and team have done a great job sort of driving down costs, and we want to give them a couple more opportunities to do that. We’re pretty confident that we have a view on where the fairway is. So I don’t think there’s a burning desire to do much exploration either north or south.

Navneet Behl: Yes, I think we are pretty confident in our geological model. So our plan is to just step up the development of the play.

Michael Scialla: Makes sense. I wanted to see on — in terms of well costs, where do you see the opportunities there? And does the Utica require a different rig? And if so, you’ve been just running one rig most of the year. Are there further efficiencies that could be had by keeping a rig running continuously in that play?

Alan Shepard: Yes. So if you think about — I’ll let Nav get into the details on rigs and things like that, but just at a real high level, the efficiencies are all on the drilling side, right? The completions is sort of pretty well known at this point. So what they’re focused on is getting drilling days down. So maybe Nav, talk about that a little bit.

Navneet Behl: Yes. Like the rigs that we have right now are fully capable of drilling the deep Utica. We don’t have any issues with that. And over the last 12 months or so, we have made really huge strides on the drilling side. We’ve been able to increase the efficiency of drilling the whole well and have cut down the days on the pad pretty much. And basically, on the drilling side, like our drilling operations are pretty steady. They’re very repeatable. And best of all, we are improving and making up big efficiency gains to get the well down faster and reduce our cost. So…

Alan Shepard: Yes. And in terms of guidance on the cost per foot, we’re still at that sort of $1,750 range for right now.

Navneet Behl: And then just to kind of add to that, like last year, our drilling costs on Utica were like about $2,200 a foot. So we are down almost 20% to $1,750 per foot.

Operator: The next question comes from Jacob Roberts from TPH.

Jacob Roberts: I wanted to start on the well outperformance that we’ve seen over the past several quarters. I’m curious if you could provide some color on if this is a function of better-than-expected declines on older vintages? Is this better new well performance? And how durable do you think these results are and how that translates to your longer-term capital efficiency plans?

Alan Shepard: Yes. I think for this year, you’re seeing 2 things, right? There’s some outperformance on the Apex assets that we acquired, in particular, some of the big pad that we brought in right when we acquired it. And then you’re seeing outperformance on some of the new products that got converted this year. In terms of long-term performance and capital efficiency ratios and things like that, that remains to be seen. But we’re — our focus is not on that, right? We’re still in the sort of flat production mode and focused on generating as much free cash flow as possible.

Jacob Roberts: Great. And then maybe if I could just ask your opinion on current in-basin demand and power generation and all that topic you hear and your thoughts there and ability to participate perhaps?

Alan Shepard: Yes. No, we’re still long term, extremely bullish on the prospect for AI generated new demand come in the basin. Obviously, we sit on an enormous resource base here that can be developed. Still in the early innings, still a lot of talk with folks about developing some of these projects, but I can’t say exactly when it’s going to occur, but it definitely — all the math suggests that Appalachia and all the gas up here needs to be part of that mix moving forward.

Nicholas DeIuliis: And Jacob, just to add to what Alan said, the other issue underneath all of this that sometimes gets lost with the excitement of AI demand and in-basin demand is the increasingly obvious need for additional pipeline infrastructure to get these low-cost BTUs and molecules from this basin, not just within the basin, but to wherever else the demand centers may be. So until that happens, AI sort of demand gets fulfilled in basin from our perspective. And then if that infrastructure gets built, other regions across the nation can start to participate more wholesomely in this AI revolution.

Operator: The next question comes from David Deckelbaum from TD Cowen.

David Deckelbaum: I just wanted to echo the sentiments, congratulations to Nick and Alan. Just also wanted to ask on — welcome. The activity for the fourth quarter, you have the frac crew coming back to work. I still wanted to get some color on the timing of the TILs. It seemed like the guidance have been more of a December time frame. I think last quarter, when we checked in, the macro perhaps seemed a little bit more precarious. And perhaps now things are tightening up a little bit. So how do you guys think about that in terms of turning on new volumes into the winter season here?

Alan Shepard: Yes. So we started the frac crews. I think we mentioned in the prepared remarks, kind of in that October time frame. So the expectation on those TILs would be sometime in December, right? So it’ll be later in the quarter. In terms of the macro for ’26, things have kind of settled into a trading range, but we’re still not to the part of winter yet where you can have a good kind of read on where we’re going to exit winter. So we’ll see. But I think activity is going to look sort of like it did last year, right? We have a concentration of completion activities in Q4 and Q1, and then you set up yourself to be able to be flexible in ’26 to respond to whatever sort of pricing environment develops.

David Deckelbaum: Appreciate that. And my follow-up is just, obviously, you guys closed a couple of deals this quarter. It seems like the basin in general that there’s been a lot more land spend through all your peers right now. I guess, is there — can you just generally speak to that environment right now? Are we just seeing a lot more horse trading or folks kind of willing to transact on single zone areas? It seems like we should be underwriting perhaps a larger land spend in the ’26 time frame and perhaps beyond as maybe these opportunities are increasing.

Alan Shepard: Yes. So maybe I’m not going to speak to the activities of some of the peers that happened down in West Virginia and Ohio. But definitely in Central PA, where we’re focused on sort of the deep Utica development in the long term, you see more interest as folks start to understand the sort of potential of the reservoir, some of the transactions we’ve seen up there. You kind of have a moment in time here where there’s an opportunity to pick up some of the acreage that still may be open or held by folks that are looking to deal with it to some of the more consolidated players in the area.

David Deckelbaum: Appreciate that. And just to confirm real quick, the acres that you sold out of the Marcellus rights, are those areas where you’ve already developed Utica or those are areas that you intend to develop Utica in the future?

Alan Shepard: Those would be the Ohio areas where we’ve already developed the Utica.

Operator: [Operator Instructions] And our next question comes from Betty Jiang from Barclays.

Wei Jiang: I want to ask about the — pretty small, but in the guidance, the increase in the non-D&C capital, what’s driving that? And as I’m hearing just more focus on deep Utica development going forward, is there a need for facility infrastructure spend going forward for you to optimize development there?

Alan Shepard: Yes. So maybe for your first question in terms of just the $7 million bump to the midpoint there, that’s really just timing. I mean we build all of our midstream and water infrastructure. So sometimes you’re just talking about a project sliding around 3 months or so, something like that. So it’s really just noise on that front. Longer term, the way we think about infrastructure development as we move to Central PA, because our decline rates are so low, there will be — need to be additional infrastructure, but it’s not going to be anywhere near the scale that you saw last decade, sort of midstream build-out cycles that occurred. We’re talking about adding a handful of pads a year. So you’re able to really just sort of meter out that spend at a different pace from what we’ve seen historically.

Navneet Behl: Yes. And I can add to that comment, too, is, as I told earlier, that we are pretty confident of the model. So we will just be moving from pad, which are contiguous to each other. And so our infrastructure spend just will be like a little bit of additional infrastructure rather than in a delineation model where you have to like delineate the wells and build a whole fairway model. So we are getting into a more efficient infrastructure spend, so which won’t change from year-to-year. It will be like pretty steady, just like we have in our drilling program.

Wei Jiang: Got it. So the non-D&C CapEx as a percent of total, probably going to be fairly steady.

Alan Shepard: I mean it will be — it won’t be anything like last decade. There will be periods where you maybe need to add a station or something like that, but it’s nothing on the scale of last year. And as Nat pointed out, the goal is to be as efficient as possible with that spend given that we’re able to kind of do return trips and have a focused development plan that just kind of steps out as opposed to needing to go to the extreme end of a field and build infrastructure to that part of it.

Wei Jiang: Great. And my follow-up is on the back to the deep Utica development. I know there’s been many questions asked around that. But what I’m hearing is the focus is really trying to get the per foot cost down. And as we have seen in the past with play development, it’s just about steady-state development and park a rig there and optimize and reduce drill time. And with one rig running, it just seems that’s not moving between the Southwest and Central that’s just not the most efficient way. Is there a possibility for us to start seeing like one dedicated rig being allocated to the Utica to maximize that efficiency?

Alan Shepard: Yes. I think you nailed it, like this industry is incredible. The engineers in the industry are incredible when it comes to optimizing development once you given up reps at any particular project, we do try to align our development plans so that we go back-to-back sort of on those types of pads. But we will have Southwest PA wells developed next year as well. So it all gets taken into consideration. But your broader point is the right one that we’re at $1,750 per foot right now is what we’re guiding to. And my expectation would be that we’re able to drive that down as the engineers do what they do.

Navneet Behl: And then to add to that, like most of our pad development, we have like 3 to 4 wells that we are testing right now, especially with the spacing of 1,300 and 1,500 feet. So us being on a 3- and a 4-well pad leads to a lot more efficiency than it would otherwise appear in other place. So our team is actually making progress almost like section by section, and that’s why you see the 20% reduction in costs. So — and that will continue to be there, right? So we will focus on increasing drilling efficiency and reducing the cost no matter what. So — and that’s the advantage that we have in CNX with the acreage position we have right now.

Operator: There are no more questions in the queue. I would like to turn the conference back over to Tyler Lewis for any closing remarks.

Tyler Lewis: Great. Thank you. Thank you again for joining us this morning. Please feel free to reach out if anyone has any additional questions. Otherwise, we look forward to speaking with everyone again next quarter. Thank you.

Operator: The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.