Good morning, and welcome to the CNX Resources Third Quarter 2025 Q&A Conference Call. Please note that this event is being recorded. I will now turn the conference over to Tyler Lewis. Please go ahead.

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?

Our first question comes from Zach Parham from JPMorgan.

First, Nick, congrats and good luck in your retirement. And Alan, congrats on your new role. First off, I just wanted to ask about 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?

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 as very attractive relative to its intrinsic value.

I wanted to ask about the Utica acquisition related to the Apex acreage. Can you provide more details? Do you have Utica rights across that position now? If not, are you considering other acquisitions to obtain more Utica rights on that acreage?

Yes. If you recall, when we did that acquisition, there were 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 underlie 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.

The next question comes from Leo Mariani from ROTH.

I wanted to see if there's any type of update on new technology 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?

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 will 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.

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?

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.

Okay. That makes sense. And just on M&A, obviously, you guys sold a little asset, bought another asset. It 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 are other Utica deals out there that you guys would like to consider?

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.

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

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 additional asset sales, it looks like the 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.

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've 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.

Great. That makes sense. Regarding the Utica acquisition in Pennsylvania, could you discuss if there are any requirements for drilling on that acreage next year? Also, is there any acreage that may be expiring soon that you plan to drill on to retain it?

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.

The next question comes from Michael Scialla from Stephens.

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?

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.

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

I wanted to ask about well costs and where you see opportunities. Does the Utica require a different rig? If that’s the case, you’ve mostly been using one rig all year. Are there additional efficiencies that could be gained by running a rig continuously in that area?

Yes. If you consider the situation, I will let Nav elaborate on the specifics regarding rigs, but at a high level, the efficiencies are primarily related to drilling. The completions are fairly established at this time. Their focus is on reducing the number of drilling days. Nav, could you discuss that a bit more?

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...

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

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

The next question comes from Jacob Roberts from TPH.

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?

Yes. I think for this year, you're seeing two 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 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.

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?

Yes. No, we're still long term, extremely bullish on the prospect for AI-generated new demand coming 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 all the math suggests that Appalachia and all the gas up here need to be part of that mix moving forward.

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 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.

The next question comes from David Deckelbaum from TD Cowen.

I want to congratulate Nick and Alan. I also have a question about the fourth quarter activity with the frac crew returning to work. I'm looking for more information on the timing of the TILs. It seems the guidance indicates a December timeframe. Last quarter, we noted that the macro conditions appeared a bit uncertain, but it seems like things might be stabilizing now. How are you approaching the introduction of new volumes as we head into the winter season?

Yes. So we started the frac crews, I think we mentioned in the prepared remarks, kind of in that October timeframe. 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 yourself up to be able to be flexible in '26 to respond to whatever sort of pricing environment develops.

I appreciate that. For my follow-up, I noticed that you closed a few deals this quarter. It appears that there has been increased land spending among your peers in that basin. Could you share your perspective on the current environment? Are we observing more negotiations or a willingness among parties to engage in transactions within single zone areas? It seems we might need to anticipate a higher level of land spending in the 2026 timeframe and possibly beyond as these opportunities seem to be on the rise.

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.

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?

Those would be the Ohio areas where we've already developed the Utica.

Our next question comes from Betty Jiang from Barclays.

I would like to ask about the increase in the non-D&C capital guidance. What is driving that? Also, with the increased focus on deep Utica development, will there be a need for facility infrastructure spending in the future to optimize development in that area?

Yes. Regarding your first question about the $7 million increase to the midpoint, it's primarily a matter of timing. We construct all of our midstream and water infrastructure, so occasionally a project may shift by about three months or so. It's really just a minor issue. In the long term, as we focus on infrastructure development in Central PA, we will need additional infrastructure due to our low decline rates, but it won't be nearly as extensive as the build-out cycles we experienced last decade. We're looking at adding just a few pads each year, allowing us to manage our spending at a different pace compared to historical trends.

Yes. And I can add to that comment, too, as I told earlier, that we are pretty confident of the model. So we will just be moving from pads, 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 delineate the wells and build a whole fairway model. So we are getting into a more efficient infrastructure spend, which won't change from year to year. It will be pretty steady, just like we have in our drilling program.

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

It will not be anything like last decade. There will be times when you might need to add a station, but it won't be on the same scale as last year. As Nat mentioned, the aim is to be as efficient as possible with our spending, especially since we can manage return trips and follow a focused development plan, rather than going to the farthest ends of a field and building infrastructure there.

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?

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 give 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.

We currently have three to four wells under testing on our pad development, particularly with spacing set at 1,300 and 1,500 feet. Operating on a three- and a four-well pad significantly improves our efficiency compared to other locations. Our team is progressing incrementally, which has contributed to a 20% reduction in costs. This trend will continue as we focus on enhancing drilling efficiency and lowering costs. Our advantageous acreage position at CNX allows us to maintain this focus.

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

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.

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