ANTERO RESOURCES Corp (AR) Q3 2026 Earnings Call Transcript

Greetings, and welcome to the Antero Resources Corporation third quarter, 2026 earnings call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce Dan Katzenberg, Vice President of Investor Relations. Thank you. You may begin.

Thank you for joining us on this Investor Conference call. We'll spend a few minutes going through the presentation that will be recalled today to Michael Kennedy for natural gas.

Thank you, Dan. The collection point for the NALNG and power projects are expected to increase demand for natural gas by more than 40 BCF per day across the U.S. by 2030, including more than 15 BCF per day in our local Appalachian region. As we have seen through our marketing efforts and highlighted by the numerous transactions announced this year, demand for natural gas assets continues to increase. Poor natural gas acreage is becoming apparent, which is resulting in higher and higher values placed on quality natural gas assets. Entero is well positioned to benefit from this inflection point, supported by more than 20 years of core integration within and being one of the few investment grades. Combined with our ongoing cost reduction initiatives, we expect these advantages to drive peer-leading free cash flow per share growth over the coming years. 1,400 core drilling locations remaining. A multi-ply, we believe this inventory advantage will become increasingly valuable. Two BCFE was achieved while curtailing per day during the quarter. An enhancement initiative, we realized our loan company history, lower than a year ago, period. And a lower cost structure led to our unhedged EBITDAX margin increasing 27% year over I'll provide an update on our margin enhancement to achieve $140 million of our $300 million target by mid-2027. The overriding royalty in 2020 met the return hurdles, resulting in 85% of the cash flow now reverting back to Intero on July 1, 2026 of annual free cash flow optimization strategy during the third quarter, resulting in $400 million per day of agreements and $20 million in annualized free cash. On increasing demand pull, only one BCF per day, optimization agreements will increase of $50 million. Next, the VPP transaction will expire in the third quarter of 2027, resulting in an annualized increase in free cash flow of 30 million. Beyond mid-2027, increased dry gas development and the expiration in 2028, and during the quarter we entered into a tract with multiple parties at the Clarington market. In addition to these sales, since announcing Antero Midstream's Eastside Express, we have seen increased interest from multiple downstream counterparties seeking access to numerous long-haul pipelines contracting with end-user demand. This project also reduces our all-end transports on the NGL macro. We have seen NGL prices increase 50%. We expect NGL strength to continue in 2027, driven by robust global demand and low international inventories that require significant U.S. exports to return to sufficient. Entero is now the only producer with meaningful NGL exposure to remain unhatched for free cash flow. Now, to provide more detail on the current liquids and NGL fundamentals, not a long ago. ...momentum seen at the U.S. butane.

Propane story has passed. 2026 propane exports are up nearly a quarter to just one withdrawal and being reflected in pricing already. Increase in LPG. The bottlenecking of dock capacity from export. As mentioned in my remarks a moment ago, Entero's current spot, C3+, International propane prices are now trading just below. Top premiums have tightened to single-digit levels.

The regional demand that this regional power get momentum on these new pipeline producers has with utilization, which is projected to nearly double towards 40 BCF by then. Antero remains differentiated from its...

In my comments today, I will focus on the financial benefits that we are already achieving from our margin enhancement strategy. Look at a comparison in benchmark prices year over year. Despite natural gas prices declining 4% year-over-year, we were able to increase our unhedged EBITDAX margin by 27 cents per NCFE, or 27%, as we benefited from a lower cost structure and high liquids exposure. Turning to slide 12, we increased production by 23%, driven by the HG acquisition and several transactions that increased working interest in our gross production base. Notably, we were able to accomplish this net production growth without impacting the basin's gross production, which has remained essentially flat at 35 to 36 BCF a day during this period. Looking across our peer group, production was essentially flat year over year. Second, we reduced our total cash costs 16% year over year, which compares to the natural gas peer group NGLs as a percent of total production margin improvement during periods of lower natural gas prices. The 27% increase in unhedged EBITDAX margin occurred while our peer group saw EBITDAX margins essentially flat during that same period. This represents the true rate of change story at Antero. Importantly, this is just the early stages of reducing our cost structure and enhancing margins. We have a clear line of sight to significant further improvements over the next 24 months. Looking beyond 2028, we are already in significant discussions around firm sales agreements that will drive material margin improvement and anticipate that total margin improvement could double our $300 million target by early next decade. May 13 compares free cash flow per share growth of the Appalachian Peer Group. We generated substantial free cash flow of over $1 billion over the last year, driven by a lower cost structure, high liquids exposure, and an attractive hedge book. We used this free cash flow to fund HG and other bolt-on transactions, reduce debt while also reducing our share count by more than 5 million shares. This resulted in a 139% increase in our free cash flow per share year over year, compared to the peer group average that was approximately flat. Looking ahead, we see the opportunity to nearly double our free cash flow per share, driven by the execution of our margin enhancement strategy, organic production growth from a three-rig and two-completion-through development plan, and meaningful share repurchases. With that, I will now turn the call over to the operator for questions.

Thank you. And at this time, we'll conduct our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. And our first question comes from Neil Mehta with Goldman Sachs. Please state your question.

Yeah, thanks for the rundown, team. I guess the first question, just on the volume guide for Q4, if there was a quarter to come in a little softer on the volume, there's probably this one given the pricing environment, but just your perspective on how much of the curtailment was because of third-party outages. We've heard about the stonewall challenges there. And then how much of that was economic curtailment as a result of the soft Appalachia pricing environment?

Yeah, the guidance is a 4.3 BCF with 15 to 20 BCF curtailments. All of those are related. When you have downstream issues in shoulder months, you'll have weak pricing. And we now have the flexibility levels are below and still produce all of our liquids. Our liquid is receiving over $60 a barrel. We, of course, produce all of those, and then any local dry gas. I'll also remind you all of that local dry gas is hedged at basis around the $0.90 level, so we are protected from that standpoint. But no reason to sell at those levels when a couple months later you can sell for $3 and $4.

Perfect. Thank you. Thanks for the caller on the improvement in NGL pricing in Q4 sequentially. Just give us a sense of how you're seeing that pricing tailwind. How should we think about that as a benefit sequentially into your fourth quarter? And while we're on it, any thoughts on the 27 setup for NGL?

Yeah, well, there's a lot of thoughts on it. You know, Q4 will basically essentially double your free cash flow from Q3. And then when you look out in revenues, and that's even with a much lower annually, if you're talking $20 incremental increase, $125 million a quarter.

Yeah, big numbers. Thanks, Steve.

Your next question comes from Gabe Dodd with Truist. Please state your question.

Thanks, operator. Good morning, guys. Thanks for taking my questions. I was hoping maybe we could start with a follow-up on Neil's question just on the realizations again, just kind of flipping from premium to discount, and obviously you noted some of the challenges. But how should we expect the differential to NYMEX to change as we progress through 27? So, differential to NYMEX and then also the differential to international propane and NGLs and also domestic. Just curious how that capture kind of looks moving forward.

Yeah, and differentials, and now that we have local dry gas, you'll see, you know, a little weakness there. In Q3, just because of some downstream outages, and that's why we're at that 30-cent level. You know, you look at Q4, you're maybe at flat optimization. So, we have a premium at the index. I have more index exposure.

Okay, yep, understood. Thanks for that. That's helpful. And then I guess as a follow-up, could you maybe talk a bit more about the Clarington supply agreement? I think maybe it's M2 plus a premium. Is that how we should expect most of these deals to kind of materialize, M and M2 plus a little bit of a premium?

Yeah, I think that's a fair assessment, really, in a day today, going to the Clarington market. So you'd probably expect to see us do a bit more of those transactions over time. That Clarington market is in the, you know, 20 to 25 cents above M2 if you can do longer term deals. If you're selling, you know, on the month or on the day, it's probably closer to like an M2 plus 10, plus 15. So it does add some nice margin to the business when you can lock it out longer term. And then I'd just say, overall, strong demand at that Clarington market. A lot of demand pull coming from that market, and so I'd expect us to move more volumes up to that market over time, just given the demand pull and the inbounds we continue to get as it relates to that demand pull at that.

Sounds good. Thanks, guys.

Your next question comes from Arun Jairam with J.P. Morgan. Please say your question.

Yeah, good morning, team. You guys are about halfway through your margin enhancement program, at least through 2028. Can you just elaborate on the next, call it 160 million of FT optimizations and the liquid FT and just maybe the timing of that and remind us what is happening there in terms of capturing that?

Yeah, we're excited. The other 60 is more dry gas developing these deals that Brendan's touched on. Local, getting the premium rolls off. So that's the other six. You can see that in our commitment.

Got it. Got it. And then, Mike, as we think about kind of cash production expense, you did 205 in the quarter, guys a little bit higher for 4Q, call it 210 to 220. How do you anticipate that kind of trending as we think about 27, again, given the margin enhancement activities, which are well underway?

Yeah, it trends down over that time. Just to remind, on Q4, it's just a tad up only because of fuel expense, nothing on the base business currently, but that goes lower as we continue to execute on these optimization, continued natural gas sales, the firm transport rolling off, that continues to trend down.

Great. Thanks, Mike. Appreciate it.

Your next question comes from Kevin McCurdy with Pickering Energy Partners. Please state your question.

Hey, good morning. Mike, you mentioned Eastside Express in your prepared remarks, and I wonder if you could expand a little bit on where that project gets your gas and what the conversations are like with end users, and will that be filled with new production, or would you be shifting gas from other markets there?

No, that basically goes east-west across our dry gas acreage, that few Tier 1 dry gas undeveloped acreage, the 100,000 acres that we have on the east side, building that all the way across, basically to connect export into that area on multiple different pipelines. I think we have seven or eight interconnects. We're getting so much interest on that. I don't know which way it's going to go or which pipes it's going to go, but that's what it does. It connects that 100,000 acres and allows for that dry gas development to find the best price. That will be a little bit, I think, of maybe some dry gas growth, but really kind of replacing much gross gas, but just more portfolio approach around our production mix going forward.

Appreciate that answer. And then for my second question, maybe on the operations side, I know in prior quarters you talked about bringing on a lean gas pad late this year. But just checking, is that liquids-rich pad new, and is that in response to the kind of the high propane and butane prices you were seeing?

No. In my initial remarks this year, we have one pad called the Barnard pad that was a duck. We were going to wait to see where prices were to complete it. It's a 1,300 BTU pad. We're completing it right now on the western side of our field. Obviously, with C3 Plus prices, $60 plus, we're completing that right now.

Perfect. Thank you. Your next question comes from David Dekelbaum with Stiefel. Please state your question.

Everyone. Hey, Mike. Thanks for taking my questions. Just wanted to ask, the update, obviously, on continuing the growth program makes a lot of sense with $60 a barrel, you know, C3 plus pricing. As we get in the next year, I think you talked about high single-digit growth, which I guess would approach that four or five plus level on average. You know, I guess, how much growth capital would you be contemplating for next year? And, you know, should we think about this similarly to 27 in such a rich C3-plus pricing environment?

Yeah, I think about it the same way with this year. I mean, our goal is to be the most capital-efficient operator in the basin, and we kind of proved that out over the past couple of years that we are. And that's keeping a consistent program of three rigs and two completion crews, And that's what our intention will be. We will always have a discretionary component to whether we complete a couple paths in the Q4, just depending on commodity prices, because we're not going to complete into known weak commodity prices in the winter or known weak liquids prices. You saw kind of that strategy play out this year. We were patient and disciplined. And then we looked in September. We decided, well, let's just hedge our lean gas at 350. You saw those hedges we added during the quarter, basically $100 million plus. They have hedges at $350 for $27 and $28, so to protect those economics. And then, of course, complete the liquids pad with $60 plus NGLs. So you're going to expect a similar capital plan next year as we had this year.

I appreciate that. Can we talk a little bit about some of the firm sales agreements? It seems like a pretty interesting source of upside to margin in the coming years. With this first deal here, how do we think about, I guess, the duration of these contracts relative to maybe some of the firm sales agreements you've looked at in the past? Like, if we're seeing incremental demand from utilities in sort of this Clarington area as we get down there, you know, should we expect that the duration of some of these contracts to be longer than what we've seen, or are these fairly, like, one- to two-year type agreements?

Yeah, I think it depends on which firm sales and which markets you're talking about. So in the Clarington market, and when we have FP rolling off as well. So in the Clarington market, a lot of times you can roll these one to two years and get those premiums. I think over time, you'll likely see those contracts extend. And then I think Mike talked about the east side lateral earlier as well. I think that rolling off, and I'll call out one in particular. I mean, we've got a contract that's about $200 million a day that we're having many discussions on just replacing that. Selling volume off of Eastside Express. And if you replace this $200 million a day contract with volume at an M2 plus contract, upwards of $75 to $80 million of margin enhancement, that's just one $200 a day contract. So that gives you some magnitude of the margin enhancement we've talked about. We've got the $300 million by year end 28. And then we talked about doubling that beyond 2028. Well, that doubling is really related to selling some of these longer I appreciate the color, guys.

Your next question comes from Jacob Roberts with TPH Research. Please see your question.

Good morning. I wanted to touch base on the $400 million a day optimization. I just want I just want to make sure, is that inclusive or included in the $1 billion target? And then when we think about that uplift of $50 million on the billion a day, or BCF a day, does that give you, is that including the lower realization, the 35% realization haircut you framed in Q2?

Yes. It gets to both. The $400 is inclusive in that one BCF, so it's a total of one BCF, and then the $50 million is net of the realization.

Okay, perfect. Perfect. And then kind of a minor modeling question. When we're thinking about that high single-digit growth in 2027, potentially, is the right starting point the 4.3 or kind of a 4.5 on an uncurtailed basis?

It's the average of 26.

Okay, perfect. So a year over year. Got it. Thank you so much.

Your next question comes from Betty Jang with Barclays. Please say your question.

Hi, good morning. A lot of my questions have been answered. Just maybe follow up on the one BCF per day, that FT. Which markets are you willing to effectively trade away for that lower transport cost? Is there a market that you would not want to reduce your exposure to? And, you know, since within Gulf Coast, you have three sub-hubs that you have exposure to. Just would love to get some more color on that.

Yeah, we're not trading it away. We're optimizing it. So it's not really market-dependent. It's just wherever, you know, there's some demand pull that's going to pay us premiums and more than the BCF. The BCF is just our invest margin.

Got it. So it could be coming from anywhere within your FD portfolio?

That's correct.

Great. And then on the Clarington, Ohio, opportunity out of your 16 BCF per day power demand outlook, maybe how much do you see that coming from Clarington, And then, you know, how big could that market become over time?

Yeah, so I think I mentioned we've got, you know, 400 a day flowing there today. I think given the demand poll we're seeing at the day, you have, you know, at least I'd call it five to six PCF a day being pulled out of that market. And so taking PCF a day is not unrealistic in terms of going additional volume at that at that Clarington market. Just, again, given the demand poll that we're seeing there and the inbounds we're getting as it relates to folks needing supply.

Okay, thanks.

Your next question comes from Philip Jungwirth with BMO Capital Markets. Please state your question.

Thanks. Good morning, guys. Just on the liquid FP optimization, recognizing you're not going to be recontracting for FAN capacity on ATEX, but is there a way this pipe could still be beneficial to Entero if it were converted to some other C3 plus line and just separately on C3 plus realizations? What are the puts and takes of elevated freight rates on Entero's export netbacks or Bellevue prices? Okay, great. And any thoughts on freight rates? Does those stay elevated and impact on export netbacks or Bellevue?

Yeah, I think for 2027, Mark.

Great. And then I know this comes up from time to time, but just in light of industry M&A, just wondering if you feel like the AR, AM structure is still optimal. Is there any argument that having AM as wholly owned could improve the competitiveness as it relates to supply deals? Are you still happy with the structure here and view AM's lower cost of capital as maybe even advantaging it, especially as capital investment opportunities increase?

Exactly. On that last point, you know, it's still an advantaged structure. You saw that play out with a large acquisition this year. In addition, AM's now positioned for the first time in quite some time to have these regional growth projects, and that will benefit from the lower cost of capital as well. And one thing you need to do in Appalachia is you need to control the midstream, and we control So, strategically, we control the midstream on our developed dream.

Thanks, son. Thanks.

Your next question comes from Subhash Chandra with StoneX. Please state your question.

Yeah, thanks. The October move, you know, we've seen so far in C3+, you know, how much of that do you think is sort of war-related? And in the event of peace, like, what sort of the drivers, what would your view be revised, Denny, for C3+. Thank you. And then I guess with the liquids pad coming on for Q and maybe with some of the curtailments, I mean, it doesn't look like there's going to be much of a move, maybe a percent one way or another, But do you think there'll be a bigger NGL emphasis in the completion schedule you have for next year?

Between the needle, you still see.

Your next question comes from Leo Mariani with Roth. Please do your question.

I just wanted to dive back into the comment around kind of high single-digit production growth in 2027 year over year. Just kind of doing some kind of back-in-the-envelope math here. It looks like it puts you guys around four and a half, you know, B's a day in 2027. And, you know, kind of prior to curtailing in 4Q, you guys weren't too far off that, kind of guiding to about four points. That implies, you know, some pretty limited organic growth, you know, next year. Just any kind of comments, you know, around that? Are you kind of purposely not trying to really put much growth in the system, you know, next year? Or just how are you thinking about it?

Yeah, I think it'll be a bit before you'll certainly see some growth, yeah.

Well, that makes sense on the curtailment. So, obviously, you guys are factoring that in. It certainly makes sense.

Exactly, and also on the duck capital, not that it will influence 27, but sort of influence on when we turn in line pads and maybe wait until the session as well.

Yep. And then just with respect to inflation, are you guys seeing any of that, you know, up there in Appalachia at this point in time? And do you think that that could potentially worsen a bit as we get into 27? Just comments around that. Not really.

Nothing material, nothing you would really know.

That's helpful. And then just on your gas price realizations, you know, kind of to start the year in 26, you guys were a little bit more, you know, optimistic that you guys would be getting, you know, kind of some premiums. I think a lot of it was due to pull from the LNG market, and I guess that really hasn't materialized, you know, at this point. Can you maybe just address that kind of dynamic in terms of maybe kind of what kind of went against you there? And do you expect maybe that trend can reverse a bit just given the strong LNG pull that we see in 27 and you can kind of get back up to some better gas prices?

Yeah, thanks for having me masturbated by all the downstream.

Appreciate it. Thank you.

Your next question comes from Paul Diamond with Citibank. Please state your question.

Thank you. Good morning, all. Thanks for taking the call. I just wanted to touch back in on FT optimization. So in your path to the initial 300, it's been kind of, you know, quick and to the point. The additional, I guess, 55 you see in 27 and 28, I guess, is that expected to be more chunky or will it be a bit more, you know, ticking and tying here and there? I guess, how do you see that? How does the timing of that coming through?

More ratable over time in 27 and 28. As we continue to sign some of these sales agreements and pick up margin, incremental margin on each of those agreements, you'll see that $55 million achieved. So ratable throughout the next couple of years is a good way to think about it.

Got it. Understood. And then just actually sticking on the FT optimization beyond 28, I know you guys talked about doubling the current plan, so an additional $300 million. I guess, is that more on just FT, like, contract role, or should we think about more, you know, optimization or sales or more, like, actionable moves?

Yeah, I mean, the easy way to think about it is, you know, you have some portions of our FT portfolio. When you look at the all-in netback and all-in cost, demand variable, all that it takes to get to certain delivery points that are upwards of, you know, $1.35, $1.40 back of Henry Hub. Well, if you look out at the local price, you know, you're $6.00 Henry, and a lot of these agreements that we're looking at with counterparties that need the supply, they're willing to pay a premium on top of that. So if you can replace volume, significant volume that's $1.35 back of Henry with stuff that's, you know, call it 55 to 60 cents back of Henry in basin, that's the big driver of that doubling of margin that we see. So we're not even assuming you're, you know, we're going to keep the good FT that goes with a strong LNG pull, but the FT, we're going to optimize the FT when it's rolling off and replace that with longer term sales agreements in basin. And we're seeing a lot of, like I said, a lot of interest on those deals. So feel very confident about that ability to be able to double that $300 million target.

Understood. Appreciate the clarity. I'll leave it there.

Your next question comes from John Abbott with Wolf Research. Please state your question.

Hey, thank you for answering our questions, and I'm on for Doug. The first question is, in your opening remarks, you just talked about the premium being paid for core acreage and how it's a dwindling amount. How does that change your thoughts about potential M&A from either both a buyer or seller perspective? Is more scale necessary since we're seeing more consolidation?

Well, we're about to control a lot of the trans-logical buyer and synergies that we're Appreciate it.

And then when you see this sort of spike in NGL pricing in 2027, I mean, you are going to continue with your share repurchases. How do you think about buybacks versus just sort of parking cash on the back? I mean, do you just continue to buy? You think about this as sustainable? Do you take a more cautious approach? How do you approach buybacks when you sort of see this sort of outlook?

Depending on, you know, we're highly a million shares. We hope to continue to do that at these levels.

Appreciate it. Thank you very much for taking our questions.

Your next question comes from John Anis with Texas Capital. Please state your question.

Hey, good morning, guys, and thanks for taking my questions. For my first one, the HG assets are already showing significant DNC improvements relative to the prior operator. Can you provide some color on what you've done differently to achieve those efficiencies? And then looking ahead, what additional levers do you see to drive further gains?

Operate 15 years. We have over 1,500 wells, which is the best in the business to do it. He was doing three or four stages per day of completions. We do 13 to 14. So that's efficiencies. The drilling days, too, to those assets, and we've done that. So that's how we've been able to achieve the synergies. I think we said 70-digit in that, over $100 million for the year on that, and those will continue going forward.

Got it. And for my follow-up, as you look to optimize both natural gas and liquids transport, I'm curious how you weigh reducing fixed commitments today versus your ability to capture premium pricing or serve new demand later along your FT pathway, or is it that the portfolio can become both lower cost and more flexible?

We have 28 paths, so we know exactly which ones are margin-enhancing and which ones are not. That knowledge is invaluable as we go forward, and so we'll be able to pick the highest margins and then the ones that may not be as margin-enhancing replace local natural gas sales. Makes sense. Thanks for the time.

And your next question comes from Josh Silverstein with UBS. Please see your question.

Good morning, guys. Outside of the sales agreement, I think every company, like you guys or your peers, are starting to look at ways to enhance their revenue or kind of look at commercial marketing optimization. Part of this is maybe storage or looking at different FTE capacity. How are you thinking about the revenue side versus just the cost side, which you've outlined?

So we already captured it through all the transport we have. Others don't have the transport, so they're trying to, equity volumes, capture the real margin by button and get the R and the U.S. pricing, and then that way we can continue to reduce.

Got it. And then, you know, near record or a record lateral this quarter around 25,000 feet. Can you just talk about the ability to keep going down that path, getting towards the 20,000-foot kind of average lateral, and then maybe just some of the thoughts around the economic enhancements by doing this?

Yeah, significant economic, 18,000 feet, much longer. We continue to, I think, in the coming years, you'll probably see us. Maybe next year and then we'll continue to push and push. And, you know, the beauty of HD and now our Eastside Express acres is we can perfectly plan it. And I think you touched on the number, you know, you get five wells going north 20,000 feet, five going south 20,000 feet. And that seems to be the perfect plan with one high pressure, the middle of a row. So that's where we're heading. I think you'll see that.

Thank you. And we have reached the end of the question and answer session, so I'll now hand the floor back to Dan Katzenberg for closing remarks.

I'd like to thank everybody for joining us on the conference call today. If you have any more questions, please feel free to reach out. Have a good day.

Thank you. All parties have now disconnected.