CNX Resources - Earnings Call - Q3 2025

Executive Summary

• Q3 2025 delivered solid operating performance with adjusted operating margin up to 42% and adjusted EBITDA of $296M, despite lower NYMEX pricing and sequentially lower volumes; GAAP diluted EPS was $1.21 and total revenue and other operating income was $583.8M.
• Guidance improved: CNX raised 2025 free cash flow to ~$640M and FCF/share to ~$4.75, increased production guidance to 620–625 Bcfe, and lifted expected asset sales to ~$115M; adjusted EBITDAX guidance was trimmed to $1,200–$1,225M while total CapEx moved up to $475–$500M.
• Strong capital returns: CNX repurchased ~$182.4M of stock in Q3, citing attractive valuation and robust free cash flow generation as drivers.
• Strategic updates and catalysts: Deep Utica costs fell ~20% YoY to ~$1,750/ft with management targeting further efficiencies; management reiterated “maintenance mode” into 2026 and highlighted growing in‑basin AI demand and the need for pipeline infrastructure.
• Leadership transition: Alan Shepard to become CEO on January 1, 2026; stability of strategy and capital allocation emphasized.

What Went Well and What Went Wrong

What Went Well

• Raised 2025 free cash flow and per‑share guidance (to ~$640M and ~$4.75) while increasing production guidance to 620–625 Bcfe, signaling stronger cash generation and volume trajectory for the year.
• Deep Utica cost reductions: “We are down almost 20% to $1,750 per foot,” with ongoing drilling efficiency improvements and repeatability across pads.
• Capital returns and discipline: “Primary driver [of buybacks] was…significant free cash flow…we continue to view the business valuation very attractive relative to its intrinsic value,” supporting ~$182M in Q3 repurchases.

What Went Wrong

• Adjusted EBITDAX guidance lowered to $1,200–$1,225M, reflecting softer NYMEX pricing and higher CapEx in the back half; adjusted EBITDA declined sequentially to $296M from $330M in Q2.
• Sequential production declines through Q3 ahead of Q4 TILs; average daily production fell to 1,753 MMcfe from 1,842 MMcfe in Q2, consistent with front‑half weighted completions.
• Elevated reliance on asset sales to achieve raised FCF (from ~$50M to ~$115M), and total CapEx increased (to $475–$500M), modestly tightening the cash conversion balance.

Transcript

Operator (participant)

Good morning and welcome to the CNX Resources third-quarter 2025 Q&A conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's remarks, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. Please note this event is being recorded. I would now like to turn the conference over to Tyler Lewis. Please go ahead.

Tyler Lewis (VP of Investor Relations)

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 in 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?

Operator (participant)

Thank you. We will now begin the question and answer session. To ask a question, you may press star then one on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Our first question comes from Zach Parham from JPMorgan. Please go ahead.

Zach Parham (Analyst)

Thanks for taking my questions. First, Nick, congrats and good luck in your retirement. Alan, congrats on your new role.

Alan Shepard (President and CFO)

Thanks, Zack.

Zach Parham (Analyst)

First off, just wanted to ask on the buyback. You had a sizable buyback during 3Q. It was the highest since, I think, 4Q 2022. Can you talk about what drove that uptick in buybacks and how you think about the pace of the buyback going forward?

Alan Shepard (President and CFO)

Yeah, I think the primary driver was this is 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.

Zach Parham (Analyst)

Thanks. 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 you looking to make other acquisitions where you could get more Utica rights on that acreage?

Alan Shepard (President and CFO)

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. 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 in and leverage all that infrastructure, kind of like we envisioned when we did the acquisition.

Zach Parham (Analyst)

Thanks. Appreciate the color.

Operator (participant)

The next question comes from Leo Mariani from ROTH. Please go ahead.

Leo Mariani (Senior Research Analyst)

Hey guys, wanted to see if there's any type of update on new tech here specifically. Was just curious if there's any update on the oil field service, AutoSep Business, perhaps the CNG, kind of LNG Business, and just status of 45Z as you guys see it.

Alan Shepard (President and CFO)

Yes, let's start with 45Z. We're still in the period where we're waiting for the notice of final rulemaking on 45Z. We expect that before the end of the year. 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, you know, the government reopening and things like that. 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 oil field 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 2026 as of yet.

Leo Mariani (Senior Research Analyst)

Okay. 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's not a whole lot different in 2026, and would that be similar for spending as well? How are you guys thinking about that?

Alan Shepard (President and CFO)

Yeah, 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 going into winter, full storage, and we'll see what kind of weather we get this winter. 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 (Senior Research Analyst)

Okay, that makes sense. Just on M&A, obviously, you guys sold a little asset, bought another asset, seems kind of longer term, neutral on cash. What's the company's appetite in general for deals? Do you see other things you'd like to pick up in Appalachia, and perhaps there's other, you know, Utica deals out there that you guys would like to consider?

Alan Shepard (President and CFO)

We look at everything that comes to market. Our threshold is acquiring ourselves. Unless there's an opportunity that out competes that opportunity, you won't see us do anything. That's sort of how we think about it. We're certainly open to anything.

Leo Mariani (Senior Research Analyst)

Thank you, guys.

Operator (participant)

The next question comes from Noah Hungness from Bank of America. Please go ahead.

Noah Hungness (Energy Equity Analyst)

Morning guys. 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 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'm just hoping to unpack some of the moving parts there.

Alan Shepard (President and CFO)

The way to think about that is our free cash flow guidance includes all working capital adjustments. Right? 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. You're going to see movements like you see here, where we're refining guidance throughout the year. We're still confident we'll be at kind of the range we got to, $575 million free asset sale number.

Noah Hungness (Energy Equity Analyst)

That makes sense. On the Utica acquisition here in Pennsylvania, could you maybe talk about there are any requirements for drilling on that acreage next year or is there any acreage that may be expiring your term that you'll want to drill on to hold?

Alan Shepard (President and CFO)

We plan to develop the field. Obviously that's part of the underwriting case for making the investment. The exact timing of that development not going to get into at this point, but you'll see that folded into our development plan in the years ahead.

Noah Hungness (Energy Equity Analyst)

Great, thank you.

Operator (participant)

The next question comes from Michael Scialla from Stephens. Please, go ahead.

Michael Scialla (Energy Equity Research Analyst)

Good morning. Had a couple 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 you plan to stay kind of in that area that you've been developing so far?

Alan Shepard (President and CFO)

I think the plan for next year is really just focus on sort of the operational side of it. 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. I don't think there's a burning desire to do much exploration, either north or south.

Navneet Behl (COO)

Yeah, I can add to that. Sorry, go ahead.

Alan Shepard (President and CFO)

No, go ahead. Go ahead, Nav.

Navneet Behl (COO)

Yeah. I think we're pretty confident in our geological model. Our plan is to just step up the development of the play.

Michael Scialla (Energy Equity Research Analyst)

Makes sense. I wanted to see, in terms of well costs, where do you see the opportunities there? Does the Utica require a different rig? 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 (President and CFO)

Yeah. If you think about it, 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. The completions is sort of pretty well known at this point. What they're focused on is getting drilling days down. Maybe Nav can talk about that a little bit.

Navneet Behl (COO)

Yeah. The rigs that we have right now are fully capable of drilling the deep Eureka. We don't have any issues with that. Over the last 12 months or so, we've made really huge strides on the drilling side. We've been able to increase the efficiency of drilling the whole well. I've cut down the days on the pad pretty much. Basically, on the drilling side, 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.

Alan Shepard (President and CFO)

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

Navneet Behl (COO)

Yeah. Just to kind of add to that, like last year our drilling cost on Utica were like about $2,200 a foot. We are down almost 20% to $1,750 per foot.

Michael Scialla (Energy Equity Research Analyst)

Sounds good. Thank you, guys.

Operator (participant)

The next question comes from Jacob Roberts from TPH. Securities. Please go ahead.

Jacob Roberts (Analyst)

Morning. 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 well declines on older vintages. Is this better new well performance? How durable do you think these results are, and how that translates to your longer-term capital efficiency plans?

Alan Shepard (President and CFO)

Yeah, I think for this year you're seeing two things, right? There's some outperformance on the Apex acreage we acquired. In particular, it's kind of the big pad that we brought in right when we acquired it. Then you're seeing outperformance on some of the new pods that got converted this year, you know, in terms of long-term performance and capital efficiency ratios and things like that. That, you know, remains to be seen. We're, you know, our focus is not on that, right? You know, we're still in the sort of flat production mode and focused on generating as much free cash flow as possible.

Jacob Roberts (Analyst)

Great, thank you. Maybe if I could just ask your opinion on current in-basin demand and power generation and all that, you know, topic du jour and your thoughts there and ability to participate, perhaps?

Alan Shepard (President and CFO)

Yeah, we're still long-term extremely bullish on the prospect for AI-generated new demand coming to 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 can't say exactly when it's going to occur. It definitely, all the math suggests that Appalachia and all the gas up here needs to be part of that mix moving forward.

Navneet Behl (COO)

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. Until that happens, AI sort of demand gets fulfilled in-basin from our perspective. If that infrastructure gets built, other regions across the nation can start to participate more wholesomely in this AI revolution.

Jacob Roberts (Analyst)

Thank you, guys. Appreciate the time.

Operator (participant)

The next question comes from David Deckelbaum from TD Cowen. Please go ahead.

David Deckelbaum (Analyst)

I just wanted to echo the sentiments. Congratulations to Nick and Alan. I just also wanted to ask on the activity for the fourth quarter. You have a frac crew coming back to work. Still wanted to get some color on the timing of the tills. It seemed like the guidance had been more of a December timeframe. 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. How do you guys think about that in terms of turning on new volumes into the winter season here?

Alan Shepard (President and CFO)

Yes, we started the frac crews. I think we mentioned in the prepared remarks kind of that October timeframe. The expectation on those tills would be sometime in December, a little bit later in the quarter. In terms of the macro for 2026, things have kind of settled into a trading range. We're still not to the part of winter yet where you can have a good read on where we're going to exit winter. We'll see. I think activity is going to look sort of like it did last year, where you have a concentration of completion activities in Q4 and Q1, and then you set up yourself to be able to be flexible in 2026 to respond to whatever sort of pricing environment develops.

David Deckelbaum (Analyst)

Appreciate that, my follow-up is just obviously you guys crossed a couple deals this quarter. 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 2026 time frame and perhaps beyond, as maybe these opportunities are increasing.

Alan Shepard (President and CFO)

Yeah. Maybe I'm not going to speak to the activities of, you know, 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, you know, held by folks that are looking to deal it to some of the more consolidated players in the area.

David Deckelbaum (Analyst)

Appreciate that. 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 are those areas that you intend to develop Utica in the future?

Alan Shepard (President and CFO)

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

David Deckelbaum (Analyst)

Appreciate it, guys.

Operator (participant)

Again, if you have a question, please press star then one. Our next question comes from Betty Jiang from Barclays. Please go ahead.

Betty Jiang (Senior Equity Research Analyst)

Good morning. Thank you for taking my question. I want to ask about the pretty small, but in the guidance, the increase in the non-DNC capital, what's driving that? As I'm hearing just more focus on the Utica development going forward, is there a need for facility infrastructure spend going forward for you to optimize development there?

Alan Shepard (President and CFO)

Yes, 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 three months or so, something like that. 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 need to be additional infrastructure, but it's not going to be anywhere near the scale that you saw last decade. The 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 (COO)

Yeah, I can add to that comment too. As I told earlier, we're pretty confident of the model. We will just be moving from pad which are contiguous to each other, and our infrastructure spend will just be a little bit of additional infrastructure rather than in a delineation model where you have to delete the wells and build a whole fairway model. We are getting into a more efficient infrastructure spend, which won't change from year to year. It'll be pretty steady, just like we have our drilling program.

Betty Jiang (Senior Equity Research Analyst)

Got it. So non-D&C CapEx as percentage of total probably going to be fairly steady.

Alan Shepard (President and CFO)

I mean it won't be anything like last decade. There'll be periods where you maybe need to add a station or something like that, but it's nothing on the scale of last year. As Nick pointed out, the goal is to be as efficient as possible at 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.

Betty Jiang (Senior Equity Research Analyst)

Great. 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. 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. 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 one dedicated rig being allocated to the Utica to maximize that efficiency?

Alan Shepard (President and CFO)

Yeah, I think you nailed it. This industry is incredible. The engineers in the industry are incredible when it comes to optimizing development. Once you give enough reps at any particular project, we do try to align our development plan so that we go back to back on those types of pads. We will have Southwest PA wells develop next year as well. It all gets taken into consideration. Your broader point is the right one that we're at $1,750 per foot right now is what we've got into. My expectation would be that we're able to drive that down as the engineers do what they do.

Navneet Behl (COO)

To add to that, most of our pad development, we have three to four wells that we are testing right now, especially with the spacing of 1,300 and 1,500 ft. Us being on a three and a four-well pad leads to a lot more efficiency than it would otherwise appear in other places. Our team is actually making progress almost section by section, and that's why you see the 20% reduction in costs. That will continue to be there. We will focus on increasing drilling efficiency and reducing the cost, no matter what. That's the advantage that we have in CNX with the acreage position we have right now.

Betty Jiang (Senior Equity Research Analyst)

Great. Helpful color. Thank you.

Operator (participant)

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 (VP of Investor Relations)

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'll look forward to speaking with everyone again next quarter. Thank you.

Operator (participant)

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