Antero Resources Corporation (AR) Earnings Call Transcript

Greetings, and welcome to the Antero Resources Corporation Third Quarter 2026 Earnings Call. [Operator Instructions] 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 for Antero's Third Quarter 2026 Investor Conference Call. We'll spend a few minutes going through the financial and operating highlights, and then we'll open it up for Q&A. I would also like to direct you to the homepage of our website at anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call. Today's call may contain certain non-GAAP financial measures. Please refer to our earnings press release for reporting disclosures regarding such measures. Joining me on the call today are Michael Kennedy, CEO and President; Brendan Krueger, CFO; and Dave Cannelongo, Senior Vice President of Marketing and Transportation; and Justin Fowler, Senior Vice President of Natural Gas I will now turn the call over to Mike.

Thank you, Dan. Good morning, everyone. We're at a supply-demand inflection point for the natural gas market, LNG 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. The scarcity of core natural gas acreage is becoming apparent, which is resulting in higher and higher values placed on quality natural gas assets. . Antero is well positioned to benefit from this inflection point, supported by more than 20 years of core drilling inventory, our integration with Antero Midstream and being one of the few investment-grade companies. 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. As depicted on Slide #3, per recent public analysis by Enverus, we have more than 1,400 core drilling locations remaining that gives Antero a multi-decade runway of premium inventory at a time when high-quality drilling locations are becoming increasingly scarce. As demand moves ahead of supply, we believe this inventory advantage will become increasingly valuable. Now let's move to Slide #4, which summarizes some of our quarterly highlights. Production increased 23% year-over-year to a company record of 4.2 Bcfe per day. This was achieved while curtailing in excess of 100 million per day during the quarter. Second, as a result of our cost reduction and margin enhancement initiatives, we realized our lowest cash cost level in company history, 16% lower than the year ago period. Third, the diversity of our production and a lower cost structure led to our unhedged EBITDAX margin increasing 27% year-over-year despite natural gas prices declining 4%. We used the strong financial performance to repurchase 1.6 million shares during the quarter and now have reduced our share count by more than 5 million shares since the beginning of 2025. Turning to Slide #5, I'll provide an update on our margin enhancement progress. Based on transactions we have executed on the date, we expect to achieve $140 million of our $300 million target by mid-2027. The overriding royalty interest transaction we entered into in 2020 met the return hurdles resulting in 85% of the cash flow now reverting back to Antero on July 1, 2026, or $60 million of annual free cash flow uplift. We also executed on our firm transportation optimization strategy during the third quarter, resulting in $400 million per day of agreements and $20 million in annualized free cash flow. During the fourth quarter, we are launching a formal process to expand on this strategy. Based on increasing demand pull interest that we are seeing, we expect approximately 1 Bcf per day of firm transportation optimization agreements, resulting in an annualized free cash flow 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 of liquids firm transport in 2028 puts us comfortably on track to hit our initial $300 million margin enhancement target. In addition, during the quarter, we entered into attractive natural gas term sales deals with multiple parties at the Clarington market. In addition to these sales, since announcing Antero Midstream's East Side Express pipeline last quarter, we have seen increased interest from multiple downstream counterparties seeking access to our natural gas at Interconnect on the pipeline. This project gives us widespread connectivity to numerous long-haul pipelines, providing exceptional optionality for contracting with end user demand. This project also reduces our all-in transport costs, resulting in higher margins. I'll end with brief comments on the NGL macro. The start of the fourth quarter has seen NGL prices increase 50% above the third quarter level. 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 levels. Following a recent industry transaction, Antero is now the only producer with meaningful NGL exposure going forward. We remain unhedged on our NGLs providing considerable upside to our free cash flow. Now to provide more detail on the current liquids and NGL fundamentals. I'm going to turn it over to our Senior Vice President of Marketing and Transportation; Dave Cannelongo for his comments.

Antero's liquids pricing increased throughout the third quarter following the Strait of Hormuz ceasefire ending in July and global liquids pricing rising steadily thereafter. The pricing momentum seen at the end of the third quarter has continued with Antero C3+ spot liquids realizations now testing levels not seen since early 2022. . The current geopolitical situation has had the greatest influence on the heavier end of the NGL barrel, particularly butanes and pentanes plus. These products are critical components in gasoline blending and therefore, are being bolstered by the current strength in gasoline prices as well as robust export demand for butane. As shown on Slide #6, U.S. butane exports set all-time records in May this year at 893 barrels per day and remained elevated throughout the third quarter according to ship tracking data as international buyers scrambled to replace a steadily increasing number of lost Middle Eastern butane cargoes. The price impact of these dynamics is seen on Slide #7. The chart on the left shows the volume percentages of Antero's C3+ NGL barrel. The chart on the right shows the revenue contribution by product and realized pricing in the third quarter. Despite Antero's propane volume making up 57% of the C3+ barrel, propane only contributed 43% of the revenue in the third quarter as butanes and pentane's plus prices were exceptionally high. However, the propane story has vastly improved since the third quarter. We have had significant -- a significant increase in propane pricing in recent weeks as winter restocking and revised market beliefs of a more prolonged duration to the complex in the Middle East are requiring buyers to address the realities of the lost global supply heading into peak heating demand season. On the export side, robust domestic demand for winter seasonal gasoline blending has tempered butane exports and immediately opened up more export capacity for propane at existing terminals. Second half 2026 propane exports are up nearly 0.25 million barrels per day compared to the same period in 2025 according to ship tracking data, which is double the year-over-year increase seen in the first half of 2026 when there was intense competition with butane for dock space. The impact of these trends on U.S. propane balances is already apparent and will likely be amplified throughout the coming winter withdrawal season. As shown on Slide #8, strong export demand in September and October has returned propane inventories to historical norms in the 5-year range and sharp contrast compared to the second quarter when stocks were well above the 5-year range. As a result, the EIA has reported a withdrawal 6 of the last 7 weeks compared to just one withdrawal in 2025 over the same period. This signals at the start of the withdrawal season is happening much earlier than typical. This is being reflected in pricing already as Mont Belvieu propane prices have rallied $0.34 per gallon since the start of October. Going forward, prices for both protane and butane will see tailwinds from new dock expansions coming online in the end of 2026 and into 2027. The increase in LPG export demand is well timed as VLGC ship deliveries in 2027 will be at an all-time high of 47%, up from 38 expected deliveries in 2026 as illustrated on Slide #9. The debottlenecking adopt capacity from export expansions paired with new ship deliveries points to supported forward netbacks and continued historical highs for propane and butane export volumes. The chart on Slide 9 of the [indiscernible] ship order book is consistent and likely to set another ship delivery record in 2029 as we finish out this decade. As mentioned in my remarks a moment ago, Antero's current spot C3+ NGL prices are at the highest levels realized since 2022. Given the current geopolitical and supply-side realities, the bullish trends impacting NGL prices are expected to continue and likely even escalate in the coming quarters. International propane prices are now trading just below record pricing levels seen back in March of 2026 and at the start of the operation of the Fury conflict. Stock premiums have tightened to single-digit levels. Mont Belvieu prices have risen as a result, consistent with Antero's predictions and prior earnings calls. Critically, Antero has far more exposure from increasing NGL prices than any other producer due to our high percentage of liquids production and completely unhedged portfolio. With that, I will turn it over to our Senior Vice President of Natural Gas, Justin Fowler.

Thanks, Dave. I'll start on Slide #10 that illustrates the regional demand that is expected in our Appalachian Basin. On past quarterly calls, we have focused on injections for regional demand from power projects. This chart details this demand, which today is estimated at nearly 10 Bcf per day, which includes approximately 6 Bcf that is already in service or under construction and another 4 Bcf that is waiting on FID. Now in addition to this regional power demand, there has more recently been significant momentum on incremental demand pull pipelines, which we estimate to be over 6 Bcf per day. What is noteworthy about these new pipelines is that are being underwritten by end user demand, such as utilities and LNG facilities. This compares to the past when producers had to take on these commitments to push volumes out of the basin. This shift from producer push to the demand pull ultimately improves pricing netbacks and margins for Antara. Unique to Antero, this demand provides significant competition for our natural gas volumes and firm transportation capacity. As we enter the latter part of this decade, natural gas fundamentals continue to strengthen, incentivized by a sharp increase in international prices, LNG exports have recently hit record levels of over 21 Bcf per day with utilization rates near all-time highs. Higher international pricing and low storage levels are likely to ensure that this significant backlog of LNG projects, which is projected to nearly double towards 40 Bcf by the end of the decade come to fruition. Antero remains differentiated from its peers as the only producer with significant exposure to both this regional power demand and the LNG fairway through our firm transportation portfolio. With that, I will turn it over to Brendan Krueger, CFO of Antero Resources.

Thanks, Justin. In my comments today, I will focus on the financial benefits that we are already achieving from our margin enhancement strategy. Starting on Slide 11, we 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 $0.27 per Mcfe 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 cost 16% year-over-year, which compares to the natural gas peer group average, which saw costs increase 4%. And third, we produced the highest volume of NGLs as a percent of total production, which drives 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. Slide 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, reduced 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 3 rig and 2 completion [indiscernible] development plan and meaningful share repurchases. With that, I will now turn the call over to the operator for questions.

[Operator Instructions] And our first question comes from Neil Mehta with Goldman Sachs.

Thanks for the rundown team. I guess, first question, just on the volume guide for Q4, if there was a if there was a quarter to come in a little softer on the volumes, it's probably this one given the pricing environment. But -- just your perspective on how much is 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?

Yes. The guidance is at 4.3 Bcf at 15 to 20 Bcf curtailments. All of those are related on -- when you have downstream issues in shoulder months in September and October, you'll have weak pricing, and we now have the flexibility with our local dry gas to shut in local dry gas when the prices are at $1.25 levels or below and still produce all of our liquids or liquids receiving over $60 a barrel. We, of course, produce all of those and then any local dry gas exposure we have. We shut that in. I 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. And a couple of months later, you can sell it for $3 and $4.

Perfect. And thanks for the color 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?

Yes. There's a lot of thoughts on it. Q4, basically essentially double your free cash flow from -- and then when you look out even with the backwardation in '27, you're about $3 billion of EBITDA with today's prices. So you have substantial increase in revenues -- and that's even with a much lower backwardated price in '27 and just looking at $60 for Q4. It's obviously clearly significant to us. Just to remind everyone on the call on yourself, we produced 45 million barrels of C3+ annually. If you're talking $20 incremental increase from this past quarter, that's $900 million of incremental free cash flow. So or $225 million a quarter. .

Your next question comes from Gabe Daoud with Truist.

I was hoping maybe we could start with -- 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 they progress through '27? So differential to NYMEX and then also the differential to international propane and NGLs and also domestic. Just curious how that captured kind of looks moving forward.

Yes. And differentials. Obviously, third quarter is always the weakest in the industry, you've always got September and October is kind of your widest differential. And now that we have local dry gas, you'll see a little weakness there. A little more pronounced in Q3 just because of some downstream outages, and that's why we're at that $0.30 level. You look at Q4, you're maybe in the $0.20 range. So you get a little bit of improvement. And when you look at '27, you're maybe flat to dieback. Also remember, a lot of that is our firm transportation optimization. So we're able to get others to pay us a bit of a premium at the index have more index exposure and not have the transport expense. So there is a benefit on our cash cost that's more than offsetting those differentials.

Okay. Yes. Understood. 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 2 plus a premium. Is that how we should expect most of these deals to kind of materialize at Mt plus a little bit of a premium?

Yes, I think that's a fair assessment. So if you look at those transactions, a little over $250 million a day we have about 400 million 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 $0.20 to $0.25 above M2 if you can do longer-term deals, if you're selling on the month or on the day, it's probably closer to like an M to 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, I think we see very 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 market. .

Your next question comes from Arun Jayaram with JPMorgan.

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 of FT optimizations in the liquid FT and just maybe the timing of that and remind us what is happening there in terms of capturing that margin growth.

Yes, we're trying one of those is obviously just the expiration of our liquids transport. I believe it's 100 million of the 160 million remaining. The other 60 million is more dry gas development in these deals that Brendan has touched on local premium pricing on that as other transport rolls off. So that's the other 60 million. But 100 million is just the expiration of those liquids contracts. You can see that in our commitment table.

Got it. Got it. And then, Mike, as we think about kind of cash production expense, you did 205 million in the quarter, is a little bit higher for got 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.

Yes, it trends down over that time. Just to remind on Q4, it's just a tad up only because of fuel expense, a little higher commodity prices, nothing on the base business. The base business is kind of flat at that [ $2.05 ] level. currently, but that goes lower as we continue to execute on these firm transport optimization agreements and also as we kind of booked continued natural gas sales agreements locally with burn transport rolling off, that continues to trend down and definitely trends down in '27. .

Your next question comes from Kevin MacCurdy with Pickering Energy Partners.

Mike, you mentioned Eastside expressed 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 Will that be filled with new production? Or would you be shifting gas from the markets there?

No, that's basically goes east west across our dry gas acreage that 1 of the last few Tier 1 dry gas undeveloped acreage, 100,000 acres that we have on the east side, building that all the way across basically to connect with our Sherwood kind of transport into that area. So you have the optionality to flow it on multiple different pipelines. I think we have 7 or 8 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 to find the best price. That will be a little bit, I think, of maybe some dry gas growth, but really kind of replacing liquids production as well. So we don't forecast much gross gas but just more of kind of a portfolio approach around our production mix going forward.

I 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 1 pad called the Barnat pad that was a DUC we were going to wait to see where prices were to complete. It's a 1,300 Btu pad. We're completing it right now on the western side of our field. Obviously, with C3+ prices, $60-plus, we're completing that right now.

Your next question comes from David Deckelbaum with Stifel.

Just wanted to ask, the update, obviously, on continuing the growth program makes a lot of sense with $60 a barrel C3+ pricing. As we get into next year, I think you talked about high single-digit growth, which I guess would approach that 4 or 5-plus level on average. I guess, how much growth capital would you be contemplating for next year? And should we think about it similarly the '27 in such a rich C3+ pricing environment?

I think about it the same way 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 3 rigs and 2 completion crews, and that's what our intention will be. We will always have a discretionary component to whether we complete a couple of pads into 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 a day of 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 can 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 we're seeing incremental demand from utilities and sort of this Clarington area as we get down there. Should we expect that the duration of some of these contracts to be longer than what we've seen? Or are these fairly like 1- to 2-year type agreements?

Yes. 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 1 to 2 years and get those premiums. I think over time, you'll likely see those contracts extend. And then I think Mike talked about the Eastside lateral earlier as well. I think the benefit there is when we have FTE rolling off, and I'll call out 1 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 each side side express. And if you replace this 200 million a day contract with volume at M2 plus contract off of that pipe, it's upwards of 75 million to 80 million of margin enhancement. That's just 1 200-a-day contract. So that gives you some some magnitude of the margin enhancement we talked about. We've got the 300 million by year-end '28. And then we talked about doubling that beyond '28. Well, that doubling is really related to selling some of these longer-term deals in basin, both at the Clarington market, but also off of East Side Express, and there may be additional pipes down the road that we'll sell off of off of AM built pipes as well that we see significant margin pick up on.

Your next question comes from Jacob Roberts with TPH Research.

I wanted to touch base on the 400 million a day optimization. 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 1 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, yes, both. The 400 is inclusive in that 1 Bcf. So it's a total of 1 Bcf and then the 50 million is net of the realization impact. .

Okay. 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 4.5 on an uncurtailed basis?

It's the average of '26 high single-digit growth over the average '26.

Okay. Perfect. So year-over-year, got it. .

Yes. Sure.

Your next question comes from Betty Jiang with Barclays.

A lot of my questions have been answered. Just maybe a follow-up on the Bcf per day, the FT, which market are you willing to effectively trade away for that lower transport costs? Is there a market that you would not want to reduce your exposure to and within Gulf Coast, you have 3 sub hubs that you have exposure to just would love to get some more color on that.

We're not trading in a way. We're optimizing it. So it's not really market dependent. It's just wherever there's some demand pull is going to pay us premiums and we'll -- we'll go out with much more than the Bcf. The BCF is just our target, and then we'll see where we get the best response and best margin improvement.

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

That's correct. .

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

Yes. So I think I mentioned we've got 400 a day flowing there today. I think given the demand pull we're seeing at that market of Bcf a day, you have at least, I'd call it, 5 to 6 Bcf a day being pulled out of that market. And so taking that 400 up another Bcf a day is not unrealistic in terms of going additional volume at that Clarington market. Just again, given the demand pull that we're seeing there and the inbounds we're getting into it relates to folks needing supply.

Your next question comes from Phillip Jungwirth with BMO Capital Markets.