Antero Resources Q3 2026 Earnings Call Transcript

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Provided by Quartr
October 29, 2026

Key Takeaways

  • Positive Sentiment: Production and margins improved materially: Third-quarter production rose 23% year over year to a record 4.2 Bcfe per day, while cash costs fell 16% and unhedged EBITDAX margin increased 27% despite a 4% decline in natural gas prices.
  • Positive Sentiment: Margin-enhancement initiatives are progressing: Antero expects to achieve $140 million of its $300 million target by mid-2027, including benefits from firm-transportation optimization, the expiration of a volumetric production payment, and additional local firm-sales agreements.
  • Positive Sentiment: NGL exposure provides significant upside: The company remains unhedged on NGLs and expects stronger propane and butane demand, export growth, and constrained international supply to support pricing; management said fourth-quarter NGL pricing could roughly double free cash flow versus the third quarter.
  • Positive Sentiment: Strong demand outlook and development flexibility: Management cited more than 40 Bcf per day of potential U.S. natural-gas demand growth by 2030, including power and LNG demand in Appalachia, while maintaining a multi-decade inventory runway and a consistent three-rig, two-completion-crew plan.
  • Neutral Sentiment: Near-term volumes will be curtailed amid weak regional pricing: Fourth-quarter guidance is 4.3 Bcf per day with 15–20 Bcf per day of curtailments, primarily reflecting downstream constraints and uneconomic local dry-gas prices; management expects year-over-year growth to resume as pricing improves.
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Earnings Conference Call
Antero Resources Q3 2026
00:00 / 00:00

There are 20 speakers on the call.

Operator

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.

Speaker 1

Thank you for joining us for Antero's third quarter 2026 investor conference call. We will spend a few minutes going through the financial and operating highlights, and then we will 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 important disclosures regarding such measures. Joining me on the call today are Mike Kennedy, CEO and President, Brendan Krueger, CFO, 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.

Speaker 2

Thank you, Dan. Good morning, everyone. We are 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.

Speaker 2

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 a 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.

Speaker 2

Second, as a result of our cost reduction and margin enhancement initiative, 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 this 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 number 5, I will provide an update on our margin enhancement progress. Based on transactions we have executed on to date, we expect to achieve $140 million of our $300 million target by mid-2027.

Speaker 2

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 MCFE 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.

Speaker 2

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 interconnects 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 will end with brief comments on the NGL macro.

Speaker 2

Part 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 am going to turn it over to our Senior Vice President of Marketing and Transportation, Dave Cannelongo, for his comments.

Speaker 3

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's 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.

Speaker 3

As shown on slide number 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 number 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 pentanes plus prices were exceptionally high. However, the propane story has vastly improved since the third quarter.

Speaker 3

We have had a significant increase in propane pricing in recent weeks as winter restocking and revised market beliefs of a more prolonged duration to the conflicts 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 a quarter of a million barrels per day compared to the same period in 2025, according to ship tracking data, which has doubled the year-over-year increase seen in the first half of 2026 when there was intense competition with butane for dock space.

Speaker 3

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 number 8, strong export demand in September and October has returned propane inventories to historical norms in the five-year range. In sharp contrast compared to the second quarter, when stocks were well above the five-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 that 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.

Speaker 3

Going forward, prices for both propane and butanes 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 number nine. The bottlenecking of dock capacity from export expansions paired with new ship deliveries points to supportive forward netbacks and continued historical highs for propane and butane export volumes. The chart on slide nine shows the VLGC 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.

Speaker 3

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 at the start of the Operation Epic Fury conflict. As dock premiums have tightened to single-digit levels, Mont Belvieu prices have risen as a result, consistent with Antero's predictions in 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.

Speaker 4

Thanks, Dave. Start on slide number 10 that illustrates the regional demand that is expected in our Appalachian Basin. On past quarterly calls, we have focused on the projections for regional demand from power projects. This chart details this demand, which today is estimated at nearly 10 Bcf per day under construction and another 4 Bcf that is waiting on FID. In addition to this regional power demand, there has more recently been significant momentum on incremental demand pull pipelines, which we estimate could be over 6 Bcf per day. What is noteworthy about these new pipelines is they're 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 demand pull ultimately improves pricing netbacks and margins for Antero.

Speaker 4

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.

Speaker 5

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 35-36 Bcf a day during this period. Looking across our peer group, production was essentially flat year-over-year.

Speaker 5

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%. 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.

Speaker 5

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, 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 3-rig and 2-completion through development plan, and meaningful share repurchases. With that, I will now turn the call over to the operator for questions.

Operator

Thank you. At this time, we will 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. Our first question comes from Neil Mehta with Goldman Sachs. Please state your question.

Speaker 6

Yeah. Thanks for the rundown, team. I guess the first question is just on the volume guide for Q4, if there was a quarter to come in a little softer on the volumes, it is probably this one, given the pricing environment. Just your perspective on how much of the curtailment was because of third-party outages. We have heard about the Stonewall challenges there. Then how much of that was economic curtailment as a result of the soft Appalachia pricing environment?

Speaker 4

Yeah. The guidance is at 4.3 Bcf with 15 Bcf to 20 Bcf curtailments. All of those are related on when you have downstream issues in shoulder months, in September and October, you will have weak pricing. 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.

Speaker 2

Still produce all of our liquids. With our liquids receiving over $60 a barrel, we of course, produce all of those, then any local dry gas exposure we have, we shut that in. Also remind you, all of that local dry gas is hedged at basis around the $0.90 level. We are protected from that standpoint, but no reason to sell at those levels when a couple of months later you can sell for $3 and $4.

Speaker 6

Perfect. Thank you. Thanks for the color on the improvement in NGL pricing in Q4 sequentially. Just give us a sense of how you are seeing that pricing tailwind. How should we think about that as a benefit sequentially into your fourth quarter? While we are on it, any thoughts on the 2027 setup for NGL?

Speaker 2

Yeah. Well, there's a lot of thoughts on it. Q4, it'll basically essentially double your free cash flow from Q3. When you look out, even with the backwardation in 2027, you're above $3 billion of EBITDA with today's prices. You have substantial increase in revenues, and that's even with a much lower backwardated price in 2027 and just looking at $60 for Q4, it's obviously clearly significant to us. Just to remind everyone on the call, we produce 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, or $225 million a quarter.

Speaker 6

Yeah, big numbers. Thanks, team.

Speaker 2

Yeah.

Operator

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

Speaker 7

Thanks, operator. Morning, guys. Thanks for taking my questions. Was hoping maybe we could start with or follow up on Neil's questions. It's on the realizations again, just kind of flipping from premium to discount. Obviously you noted some of the challenges. How should we expect the differential to NYMEX to change as we progress through 2027? So differential to NYMEX and then also the differential to international propane, NGLs and also domestically. Just curious how that captured kind of looks moving forward.

Speaker 2

Yeah, and differentials, obviously Q3 is always the weakest in the industry. You've always got September and October is kind of your widest differential. Now that we have local dry gas, you'll see a little weakness there. It's 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. When you look at '27, you're maybe a flat to a dime back. Also remember, a lot of that's our firm transportation optimization. So, we're able to get others to pay us a bit of a premium at the index, but 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.

Speaker 7

Okay. Yep. Understood. Thanks for that. That's helpful. Then I guess just 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 at an M2 plus a little bit of a premium?

Speaker 2

Yeah, 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 the $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 an M2 plus $0.10, plus $0.15. So it does add some nice margin to the business when you can lock it out longer term. Then I'd just say overall, I think we see very strong demand at that Clarington market.

Speaker 2

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.

Speaker 7

Awesome. Sounds good. Thanks, guys.

Operator

Your next question comes from Arun Jayaram with JPMorgan. Please state your question.

Speaker 8

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 margin growth?

Speaker 2

Yeah, we're excited. 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's touched on. Local getting the 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.

Speaker 8

Got it. Then, Mike, as we think about kind of cash production expense, you did $2.05 in the quarter, guidance a little bit higher for Q4, call it $2.10-$2.20. How do you anticipate that kind of trending as we think about 2027? Again, given the margin enhancement activities which are well underway.

Speaker 2

Yeah, it trends down over that time. Just to remind, on Q4, it is just a tad up only because of fuel expense, little higher commodity prices, nothing on the base business. The base business 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 book continued natural gas sales agreements locally with firm transport rolling off, that continues to trend down. It definitely trends down in 2027.

Speaker 8

Great. Thanks, Mike. Appreciate it.

Operator

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

Speaker 9

Hey, good morning. Mike, you mentioned East Side Express in your prepared remarks. 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. Will that be filled with new production, or would you be shifting gas from the markets there?

Speaker 2

No, that basically goes east-west across our dry gas acreage at one of the last 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 with our Sherwood transport into that area, so you have the optionality to flow it on multiple different pipelines. I think we have seven or eight interconnects. We are getting so much interest on that, I do not know which way it is going to go or which pipes it is going to go. That is 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 liquids production as well.

Speaker 2

We do not forecast much gross gas, but just more of a portfolio approach around our production mix going forward.

Speaker 9

Appreciate that answer. 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?

Speaker 2

No, in my initial remarks this year, we have one pad called the Barner Pad that was a DUC, that 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+ prices, $60 plus, we're completing that right now.

Speaker 9

Perfect. Thank you.

Operator

Your next question comes from David Deckelbaum with Stifel. Please state your question.

Speaker 10

Hi, everyone. Hey, Mike Kennedy. 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, C3+ pricing. As we get into next year, I think you talked about high single-digit growth, which I guess would approach that 4 Bcfe a day-5 Bcfe a day plus level on average. I guess, how much growth capital would you be contemplating for next year? And should we think about this similarly to 2027 in such a rich C3+ pricing environment?

Speaker 2

No, think about it the same way with this year. Our goal is to be the most capital-efficient operator in the basin, and we've kind of proved that out over the past couple years that we are. 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 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 that strategy play out this year. We were patient and disciplined, then we looked in September, we decided, well, let's just hedge our lean gas at $3.50. You saw those hedges we added during the quarter. Basically, 100 million plus a day of hedges at $3.50 for 2027 and 2028.

Speaker 2

To protect those economics. Then, of course, complete the liquids pad with $60 plus NGLs. You can expect a similar capital plan next year as we had this year.

Speaker 10

I appreciate that. Can we talk a little bit about some of the firm's 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's sales agreements you've looked at in the past? If we're seeing incremental demand from utilities in 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 one to two-year type agreements?

Speaker 5

Yeah, I think it depends on which firm sales and which markets you're talking about. In the Clarington market, and when we have FT rolling off as well. 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. Then I think Mike talked about the East Side lateral earlier as well. I think the benefit there is when we have FT rolling off, and I'll call out one in particular. 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 the East Side Express.

Speaker 5

If you replace this 200 million a day contract with volume at an M2 plus contract off of that pipe, it is upwards of $75 million to $80 million of margin enhancement. That is just one 200 a day contract. So that gives you some magnitude of the margin enhancement we talked about. We have got the 300 million by year-end 2028.

Speaker 4

Then we talked about doubling that beyond 2028. 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. There may be additional pipes down the road that we will sell off of AM built pipes as well that we see a significant margin pickup on.

Speaker 10

Appreciate the color, guys.

Operator

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

Speaker 11

Good morning.

Speaker 4

Morning.

Speaker 11

I wanted to touch base on the $400 million a day optimization. I just want to make sure, is that included in the 1 billion target? When we think about that uplift of $50 million on the billion a day or Bcf a day, is that including the lower realization, the 35% realization haircut you framed in Q2?

Speaker 4

Yes to both. The 400 is inclusive in that 1 Bcf, so it's a total of 1 Bcf, the $50 million is net of the realization impact.

Speaker 11

Okay, perfect. 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?

Speaker 4

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

Speaker 11

Okay, perfect. So year-over-year. Got it.

Speaker 4

Yes.

Speaker 11

Thank you so much.

Speaker 4

Sure.

Operator

Your next question comes from Betty Jiang with Barclays. Please state your question.

Speaker 12

Hi. Good morning. A lot of my question's been answered. Just maybe follow up on the 1 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? Since within Gulf Coast you have three sub-hubs that you have exposure to, just would love to get some more color on that.

Speaker 4

Yeah, Betty, we're not trading it away, we're optimizing it. It's not really market dependent. It's just wherever there's some demand pull that is going to pay us premiums, and 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.

Speaker 12

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

Speaker 4

That's correct.

Speaker 12

Great. 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 how big could that market become over time?

Speaker 4

Yeah. 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 that 16 Bcf a day, you have at least, I'd call it 5-6 Bcf a day being pulled out of that market. 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 as it relates to folks needing supply.

Speaker 12

Okay, thanks.

Operator

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

Speaker 13

Thanks. Good morning, guys.

Speaker 4

Morning.

Speaker 13

Just on the liquids FT optimization, recognizing you are not going to be recontracting for ethane capacity on ATEX, but is there a way this pipe could still be beneficial to Antero if it were converted to some other C3+ line? Separately on C3+ realizations, what are the puts and takes of elevated freight rates on Antero's export netbacks or Belvieu prices?

Speaker 3

Yeah, I think we still expect that pipeline to remain an ethane service. It is possible you could see another product move on it. That certainly out there is an idea, but we still think a number of folks in the basin will rely on that pipe for ethane transportation. So don't really see that as something that we are going to spend a lot of time or attention on. Just overall, the basin realizations, our entire strategy has been around margin enhancement. So you are going to see us optimize our portfolio as things expire at the end of 2028. Realizations may come down, but overall costs will come down more than that. I think that is kind of directionally what you will see from us, moving into the late part of the decade.

Speaker 13

Okay, great. Any thoughts on freight rates? Do those stay elevated and impact on export netbacks or Belvieu?

Speaker 3

Yeah, I think for 2027, market expectation is things will stay pretty elevated at least through the first half of the year. But as we move through CAL '27, you will start to see some relief there as well. I think the big question is: Is there actually enough U.S. supply to fill all of these dock expansions on day one? I think the answer to that is probably no, not right away. I think that will also maybe create some new perceptions in the freight market that may not be there right now. That will also help temper freight rates.

Speaker 13

Great. 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? Or 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?

Speaker 2

Exactly. On that last point, it is still an advantaged structure. You saw that play out in 2026. You saw us having M&A from both an upstream and midstream perspective, and being able to value the midstream appropriately and the upstream appropriately really helped us on our large acquisition this year. In addition, AM is 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. One thing you need to do in Appalachia is you need to control the midstream, and we control it. Strategically, there is no difference. We control the midstream on our development, on our acreage, and we will always control the midstream. So, having the lower cost of capital is a benefit.

Speaker 13

Makes sense. Thanks.

Operator

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

Speaker 14

Yeah, thanks. The October move we've seen so far in C3+, how much of that do you think is sort of war related? In the event of peace, what's sort of the drivers? Would your view be revised any for C3+?

Speaker 3

Yeah. Dave, I'll take that one, Subhash. I think oil pricing around $100 WTI, call it 100, mid-teens Brent. The prices that we're seeing right now for propane and butane in the international market delivered are very much in line with historical levels, like what you would see relative to naphtha and oil prices in those markets. I think your question is a good one around how much of this is war related driven. Well, certainly, yeah, it's had an impact obviously on liquids prices, refined products availability, et cetera. I think the thing that we've seen that's been a little bit different, you've seen a greater recovery in oil through the Strait of Hormuz than you have in LPG.

Speaker 3

If you're looking globally, we're still down about 25% of waterborne LPG due to the impacts in the Strait of Hormuz, just not as much of a recovery on the LPG side in that region. So that probably lends itself to additional tailwinds kind of relative to oil for the NGL barrel moving forward, if this continues to prolong itself. But certainly, $100 oil is going to lead to a pretty strong NGL price, and that's what you're seeing in our realizations in the fourth quarter.

Speaker 14

Yeah. Thank you. Then I guess with the liquids pad coming on 4Q and maybe with some of the curtailments, it does not look like there is going to be much of a move, maybe a percent one way or another. Do you think there will be a bigger NGL emphasis in the completion schedule you have for next year?

Speaker 2

No, it is general, like we talked about, we want balance. It is more like 50/50, kind of on a go-forward basis between the dry gas and liquids. That is not on production, that is actually on development pads. It really does not move the needle. You still save 70% liquids and 30%, or 30% liquids and 70% gas.

Speaker 14

Yeah. Thanks, Mike.

Operator

Your next question comes from Leo Mariani with ROTH. Please state your question.

Speaker 15

Hey, just wanted to dive back into the, kind of, BCFE a day in 2027. Prior to curtailing in 4Q, you guys weren't too far off that kind of guiding to about 4.45. I guess it implies some pretty limited organic growth next year. Just any kind of comments around that? Are you kind of purposely not trying to really put much growth in the system next year? Or just how are you thinking about it?

Speaker 2

Yeah, I think it will be a low 4.5, kind of a risk curtailment kind of number. If you had not unrisking and no curtailments thought about or just put in a range, I think you would be above the 4.5.

Speaker 3

I think on a year-over-year basis, if you go Q4 to Q4, you will certainly see some growth.

Speaker 2

Yeah.

Speaker 15

Okay. No, that makes sense on the curtailment. Obviously you guys are factoring that in. Certainly makes sense.

Speaker 2

Exactly. On the debt, the same thing on the production, on the DUC capital. We will always have kind of a debt component. For the Q4, not that it will influence 2027, but it will have a little bit of influence on when we turn in line pads and maybe waiting until December months to turn it on instead of like a September, October in a year can influence the production as well.

Speaker 15

Yep. Okay. Just with respect to inflation, are you guys seeing any of that up there in Appalachia at this point in time? Do you think that that could potentially worsen a bit as we get into 2027? Just comments around that would be great.

Speaker 2

Not really. We were looking at that yesterday, just trying to get our arms around it. We are really not seeing anything on the service. You see maybe 1% on raw materials on oil-based mud or a little bit on steel, but nothing material, nothing you would really note if you were not trying to dive in and analyze it.

Speaker 15

Okay, that is helpful. Just on your gas price realizations. Kind of to start the year in 2026, you guys were a little bit more

Speaker 15

Optimistic that you guys would be getting some premiums. I think a lot of it was due to pull from the LNG market, and I guess that really hasn't materialized at this point. Could you maybe just address that kind of dynamic in terms of maybe what 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 2027, and you can kind of get back up to some better gas prices?

Speaker 2

Yeah. I think September and October, we saw the lowest regional gas price we've ever seen. That wasn't anticipated. There was a couple weekends where it was $0.60. We didn't sell on those, of course, but the weakness was exacerbated by all the downstream issues that occurred in September and October. It backed it up on a historic level back up into the region. We, of course, didn't forecast that. We don't forecast it going forward, though we're obviously flexible enough to not have to sell into that. We have the ability to just wait and sell it in December. That's what went against us. That and we've been way more successful in our optimization of the firm transport than we thought, so demand pull is real. You saw that in the third quarter.

Speaker 2

When that occurs, you have slightly lower realized price, but much lower cash production expense.

Speaker 15

Okay. Appreciate it. Thank you.

Speaker 5

Sure.

Operator

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

Speaker 16

Thank you. Good morning, all. Thanks for taking the call. Just wanted to touch back in on FT optimization. In your path to the initial 300, it has been kind of quick and to the point. The additional, I guess 55 you see in 2027 and 2028, I guess, is that expected to be more chunky, or will it be a bit more ticking and tying here and there? I guess, how do you see the timing of that coming through?

Speaker 5

Yeah, I think you will see that play out more ratable over time in 2027 and 2028. As we continue to sign some of these sales agreements and pick up margin, incremental margin on each of those agreements, you will see that 55 million achieved. So ratable throughout the next couple of years is a good way to think about it.

Speaker 16

Got it. Understood. Then just actually sticking on the FT optimization beyond 2028. I know you guys talked about doubling the current plan, so an additional 300 million. I guess, is that more on just FT contract roll, or should we think about more optimization in your sales or more actionable moves?

Speaker 5

Yeah. The easy way to think about it is you have some portions of our FT portfolio. When you look at the all-in net back and all-in cost, demand variable, all that it takes to get to certain delivery points that are upwards of $1.35, $1.40 back of Henry Hub. Well, if you look out at the local price, you're $0.65 to $0.70 back of 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. If you can replace significant volume that's $1.35 back of Henry with stuff that's call it $0.55 to $0.60 back of Henry in basin, that's the big driver of that doubling of margin that we see. We're not even assuming we're going to keep the good FT that goes to the strong LNG pull.

Speaker 5

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. 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.

Speaker 16

Got it. Understood. Appreciate the clarity. Over there.

Operator

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

Speaker 17

Hey, thank you for taking our questions. I am on for Doug. First question is, in your opening remarks, you just talked about the premium being paid for core acreage and how it is 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 are seeing more consolidation?

Speaker 2

We are a buyer of acreage. Being one of the few investment-grade companies with scale already, we have an advantage. Plus, we have upstream and midstream, and we control a lot of the transport and all the infrastructure. We are the industrial builder of Northern West Virginia, so we are the consolidator of West Virginia acreage. That gives us an advantage. It is scarce, but we do surround a lot of the acreage now, so we are probably the only buyer of a lot of this, or only logical buyer. There are a lot of efficiencies and synergies that we can value, so that makes us a likely consolidator of the West Virginia area.

Speaker 17

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

Speaker 2

Yeah, we are opportunistic, depending on where the market is at. Generally, when we have buybacks, a lot of time it is on like 10b5-1 plans. We set in motion a buyback at a share price relative to propane, natural gas price, or it is kind of a two or three factor equation. We assess that every quarter. We look at where we are at versus

Speaker 2

Kind of where the commodities are at, where our free cash flow is at, where our debt's at, where our M&A opportunities are at, and set it then. We're highly opportunistic. This year, we're happy that we were able to buy in over the last kind of five quarters, 15.5 million shares. We hope to continue to do that at these levels. The opportunity seems to be there.

Speaker 17

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

Operator

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

Speaker 18

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

Speaker 2

Yeah, we brought the way that we operate to their assets, the way we've done it for the last 15 years. We have over 1,500 wells of experience, and we brought our operations team, which is the best in the business to do it. An easy one to look at is HG was doing three or four stages per day of completions. We do 13 to 14. That's always going to lend itself to a lot of efficiencies. The drilling days too, we're sub five days per 10,000 feet. They were double digits on that metric. Just those two, it's a lot of just bringing our best practices to those assets, and we've done that. That's how we've been able to achieve those. Those have been ahead of schedule. The synergies, I think we said $75 million.

Speaker 2

We're well in the triple digit in that, over $100 million for the year on that, and those will continue going forward.

Speaker 18

Got it. 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. Is it that the portfolio can become both lower cost and more flexible?

Speaker 2

Well, it's both. You see, the benefit that we have is, I think in one of the calls, we have 30 paths. I think I said it. It's exactly 28 paths. 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 best ones, capture the highest margins, and then the ones that may not be as margin-enhancing, replace those with those local firm sales or local natural gas sales agreements. We're in a great position.

Speaker 18

Makes sense. Thanks for the time.

Speaker 2

Sure.

Operator

Your next question comes from Josh Silverstein with UBS. Please state your question.

Speaker 19

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

Speaker 2

We already captured it through all the transport we have. Others don't have the transport, so they're trying to generate that without actually physically having the ability to flow their equity volumes. We've captured it through the transport, and then we're going to capture the real margin by flowing on that to the best paths to the coast and get the arb between the international pricing and the U.S. pricing. That's how we've chosen to capture it. So flowing, get to the coast, actually have our physical volumes that are being transported, and in that way, we can continue to reduce our commitments, but still enhancing our margins.

Speaker 19

Got it. Then, your 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?

Speaker 2

Yeah, significant economic enhancements. I think next year our drilling is going to average 18,000 feet, which is a record. I think this year it's maybe 15 to 16. We completed to 25. You get a lot of cost per foot advantages by going out that much longer. We continue to push it. I think, in the coming years, you'll probably see us maybe next year into next, go over 30,000. That's the goal. We'll continue to push and push. The beauty of HG and now our East Side Express, the development of that 100,000 of undeveloped natural gas acres, is we can perfectly plan it. I think you touched on the number. You get five wells going north 20,000 feet, five going south 20,000 feet.

Speaker 2

That seems to be the perfect plan with one high-pressure pipe going through the middle of a row of hundreds and hundreds of locations. That's where we're headed and to optimize that, and I think you'll see that in the coming years.

Speaker 19

Thanks.

Speaker 2

Sure.

Operator

Thank you. 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.

Speaker 1

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.

Operator

Thank you. All parties may now disconnect.

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