安特罗资源 (AR) 2026年第三季度业绩电话会：创纪录产量与NGL上行空间

安特罗资源公司（Antero Resources Corporation，纽交所代码：AR）公布2026年第三季度产量创历史新高，现金成本下降，同时强调天然气凝析液（NGL）价格上涨和运输优化是未来自由现金流的关键推动力。

核心要点

• 尽管本季度减产超过1亿立方英尺当量/日（MMcfe/d），但产量仍同比大幅增长23%，达到创公司纪录的42亿立方英尺当量/日（Bcfe/d）。
• 总现金成本同比下降16%，创公司历史最低水平。即便天然气价格下跌4%，未对冲的EBITDAX利润率仍上涨0.27美元/千立方英尺当量（Mcfe），即增长27%。
• 安特罗在本季度回购了160万股股票，自2025年初以来已减少了超过500万股股票。
• 公司预计到2027年中期将实现3亿美元年度利润提升目标中的1.4亿美元。管理层表示，到2030年代初，该提升空间可能达到最初目标的约两倍。
• 管理层表示，第四季度天然气凝析液（NGL）价格比第三季度高出50%，其中C3+现货实现价格突破60美元/桶，创下2022年以来的最高水平。
• 安特罗计划维持三台钻机和两支完井队伍的开发方案。管理层预计，与2026年平均产量相比，2027年产量将实现高单位数增长。

关键财务数据

业务与运营表现

安特罗将产量增长归因于收购HG以及提高了总生产基地工作权益的交易。管理层表示，HG的运营协同效应已超过最初7500万美元的目标，目前全年已超过1亿美元。

公司指出，在收购资产的钻井与完井效率方面取得了实质性提升。完井生产率从前运营商时代的每天约3至4段提高到每天13至14段。钻井绩效从之前的两位数天数缩短至每万英尺不足5天。

安特罗在本季度完成了一条创纪录的水平井段，长约25,000英尺。管理层预计2027年平均水平井段长度将达到约18,000英尺，并表示未来的井段可能会超过30,000英尺。

液态烃仍是提升利润率的重要驱动力。安特罗每年生产约4500万桶C3+天然气凝析液（NGL），且对这些产量保持未套期保值状态。管理层表示，如果价格在第三季度基础上每桶上涨20美元且得以维持，将意味着每年带来约9亿美元的额外自由现金流，即每季度2.25亿美元。

在C3+价格突破60美元/桶后，公司正在完成其1,300-Btu的Barnat富气井场。预计其长期开发组合将在干气井场和富气井场之间保持大致平衡，而不是大幅倾斜于NGL开发。

利润提升与运输策略

安特罗预计到2027年中期将实现每年1.4亿美元的利润提升。主要组成部分包括：

• 自2026年7月1日起生效，根据2020年重叠特许权收益交易归还的85%现金流，每年带来6000万美元的自由现金流收益。
• 通过优化1 Bcf/d的管容协议，带来约5000万美元的年化自由现金流改善。该目标包含第三季度完成的400 MMcf/d协议。
• 当按体积计算的生产支付交易于2027年第三季度到期时，将带来3000万美元的年化自由现金流收益。

管理层表示，达成最初3亿美元目标的剩余路径包括：2028年到期的液体运输合同带来约1亿美元，以及干气开发和当地溢价销售协议带来约6000万美元。

2028年之后，安特罗预计长期盆地内销售和进一步的运输优化有可能使最初3亿美元的目标翻倍。管理层提到，有可能用相对于区域基准价格具有溢价的本地合同来替代成本较高的运输路线。

East Side Express管线预计将约10万英亩未开发的干气气田与七八个管线连接点相连。管理层表示，该项目将改善市场选择灵活性，降低综合运输成本，并支持与公用事业公司及其他终端用户签订更长期的销售协议。

管理层业绩指引

管理层给出的第四季度产量指引约为4.3 Bcfe/d。当阿巴拉契亚地区的天然气价格跌至不具经济效益的水平时，公司保留削减当地干气产量的灵活性，同时继续生产利润率较高的液态烃。

展望2027年，管理层预计产量将比2026年平均产量实现高单位数增长。该展望已将潜在的减产以及已完井投产的时间灵活性纳入考量。

公司打算维持三台钻机和两支完井队伍。资本配置将保持灵活，完井时间将根据大宗商品价格进行调整。安特罗对2027年和2028年超过100 MMcf/d的贫气进行了套期保值，锁定价格约3.50美元，以保护项目的经济效益。

管理层预计，随着更多运输优化协议和当地天然气销售合同的生效，2027年的现金开采费用将呈下降趋势。由于大宗商品价格上涨导致燃料支出增加，第四季度成本可能会略有上升，但基础业务的成本底座总体保持稳定。

风险与关注领域

• 9月和10月期间，阿巴拉契亚地区的天然气价格跌至不同寻常的低位，下游停工加剧了这一状况。安特罗削减了当地干气产量，而不是在管理层所述某些周末低至约0.60美元的价格下抛售。
• NGL定价对地缘政治局势、原油价格、全球液化石油气（LPG）供应及出口需求依然敏感。管理层指出，受霍尔木兹海峡中断影响的天然气液化海运供应中，约有25%尚未恢复。
• 高企的运费可能会在至少2027年上半年对出口倒推净出厂价构成压力，不过管理层预计，随着新船运力的投产，情况将有所缓解。
• 产量增长部分取决于完井安排和减产假设。在天然气或液态烃价格疲软时期，管理层可能会推迟开采井的投产。
• 安特罗的利润策略可能会降低某些市场的报告实际售价，但管理层预计运输成本的降低将足以弥补这一影响。

分析师问答集锦

管理层表示，由于季节性疲软和下游停工，第三季度的天然气价差异常偏大。第三季度的价差约为0.30美元，预计第四季度将改善至约0.20美元。展望2027年，管理层指出实际售价可能在区域指数水平上下波动，而较低的运输成本应能支撑净利润率。

在Clarington市场，安特罗目前的输送量约为400 MMcf/d。与较短期的销售约0.10-0.15美元的溢价相比，长期协议可能在M2基准价格之上获得0.20-0.25美元的溢价。管理层表示，考虑到该市场估计有5-6 Bcf/d的需求拉动，再增加1 Bcf/d的输送量是切合实际的。

管理层还强调了利用East Side Express管线将一份200 MMcf/d的运输合同替换为基于M2加价销售协议的潜在经济效益。公司估计，单笔这种规模的交易就能带来7500万至8000万美元的年化利润提升。

在资本配置方面，安特罗表示股票回购将继续保持择机进行，并结合大宗商品价格、自由现金流、杠杆率及潜在并购机会进行综合评估。管理层指出，凭借现有的上游、中游和运输业务布局，公司有望成为西弗吉尼亚州井位资源的整合者。

业绩电话会议完整文字实录

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完整财报电话会议逐字稿

管理层陈述

Operator

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.

Daniel Katzenberg

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.

Michael Kennedy

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.

David Cannelongo

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.

Justin B. 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.

Brendan Krueger

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

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

分析师问答

Neil Mehta

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?

Michael Kennedy

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.

Neil Mehta

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?

Michael Kennedy

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. .

Operator

Your next question comes from Gabe Daoud with Truist.

Gabe Daoud

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.

Michael Kennedy

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.

Gabe Daoud

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?

Brendan Krueger

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. .

Operator

Your next question comes from Arun Jayaram with JPMorgan.

Arun Jayaram

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.

Michael Kennedy

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.

Arun Jayaram

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.

Michael Kennedy

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. .

Operator

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

Kevin MacCurdy

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?

Michael Kennedy

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.

Kevin MacCurdy

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?

Michael Kennedy

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.

Operator

Your next question comes from David Deckelbaum with Stifel.

David Deckelbaum

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?

Michael Kennedy

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. .

David Deckelbaum

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?

Brendan Krueger

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.

Operator

Your next question comes from Jacob Roberts with TPH Research.

Jacob Roberts

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.

Michael Kennedy

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. .

Jacob Roberts

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?

Michael Kennedy

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

Jacob Roberts

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

Michael Kennedy

Yes. Sure.

Operator

Your next question comes from Betty Jiang with Barclays.

Unknown Analyst

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.

Michael Kennedy

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.

Unknown Analyst

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

Michael Kennedy

That's correct. .

Unknown Analyst

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?

Brendan Krueger

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.

Operator

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

Phillip Jungwirth

Just on the liquids FP optimization, recognizing you're 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? And just separately on C3+ realizations. What are the puts and takes of elevated freight rates on Antero's export netbacks or Bellevue prices? .

David Cannelongo

Yes. I mean I think we still expect that pipeline to remain in ethane service. I mean it's possible you could see another product move on it, and that's certainly out there as an idea. But we still think a number of folks in the basin will rely on that pipe for ethane transportation. So I don't really see that as something that we're going to spend a lot of time or attention on. But yes, just overall, the basin realizations -- our entire strategy has been around margin enhancement. So you're 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. And so I think that's kind of directionally, we'll see from us moving into the late part of the decade.

Phillip Jungwirth

Okay. Great. And any thoughts on freight rates as those stay elevated and impact on export netbacks or Belvieu?

David Cannelongo

Yes. 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 the -- through Cal27, you'll 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 1. I think the answer to that is probably no, not. And so 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. .

Phillip Jungwirth

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 ARAM 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 you're still happy with the structure here and you AM's lower cost of capital is maybe even advantaging it, especially as capital investment opportunities increase.

Michael Kennedy

Exactly on that last point, it's still an advantaged structure. You saw that play out in '26. You saw it's been 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. So strategically, there is no difference. We control the midstream on our development on our acreage and we'll always control the midstream. So having the lower cost of capital as a benefit.

Operator

Your next question comes from Subash Chandra with Stonex.

Subhasish Chandra

Yes. The October move we've seen so far in C3+, -- how much of that do you think is sort of war related? And in the event of piece like what sort of the drivers, what would your view be revised any for C3+.

David Cannelongo

Yes, it's Dave. I'll take that one, Subash. I mean I think oil pacing around $100 WTI, call $100, $115 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. So I think your question is a good 1 around how much of this is more related driven. We certainly -- yes, it had an impact, obviously, on liquids prices, refined products availability, et cetera. .

And the thing that we've seen, it's been a little bit different. You've seen more -- a greater recovery in oil through the Strait of Hormuz and have an LPG and you kind of look at it globally, we're still down about 25% of waterborne LPG due to the impacts in the straighter moves, 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. .

Subhasish Chandra

Yes. And then I guess with the liquids pad coming on 4Q 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 1 way or another, but -- do you think there'll be a bigger NGL emphasis in the completion schedule you have for next year?

Michael Kennedy

No, it's general -- like we talked about, we want to balance. It's more like 50-50 in kind of on a go-forward basis between the dry gas and liquids. That's not on production. That's actually on development path. It really doesn't move the needle. You still say 70% kind of liquids and 30% liquids and 70% gas.

Operator

Your next question comes from Leo Mariani with Roth. .

Leo Mariani

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 backing envelop math here, it looks like it puts you guys around 4.5 a day and kind of prior to curtailing in 4Q because weren't too far off that kind of guiding to about 4.45. So 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 you're thinking about.

Michael Kennedy

Yes. I think it will be a little -- a 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'd be above the 4.5%.

Brendan Krueger

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

Michael Kennedy

Yes.

Leo Mariani

Okay. No, that makes sense on the curtailment. So obviously, you guys are factoring that in, certainly makes sense. .

Michael Kennedy

Exactly. And the same thing on the production on the DUC capital will always have kind of a DUC component. So for the Q4, and that will influence 27, 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 September, October and a year can influence the production as well.

Leo Mariani

Yes. Okay. And then just with respect to inflation, are you guys seeing any of that up there in Appalachia at this point in time? And do you think that, that could potentially worsen a bit as we get into 2017? Just comments around that?

Michael Kennedy

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

Leo Mariani

Okay. That's helpful. And then just on your gas price realizations, kind of at the start of the year in 2016, you guys were a little bit more optimistic that you guys would be getting 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 at this point. Could 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 2017 and you can kind of get back up to some better gas prices?

Michael Kennedy

Yes. I think September and October, we saw the lowest regional gas price we've ever seen. So that wasn't anticipated. There was like weekends, we like $0.60, we didn't sell it, of course, but the weakness was exacerbated by all the downstream issues that occurred in September and October. So backed it up on a historic level back up into the region. So -- we, of course, didn't forecast that. We don't forecast it going forward, but we're obviously flexible enough to not have to sell into that. So we are -- we have the ability to just wait and sell it in December. So -- that's kind of what went against us. Batten. -- we've been way more successful in our optimization of the firm transport, and we thought the demand pulls real. And you saw that in the third quarter. And so when that occurs, you have slightly lower realized price, but much lower cash production expense.

Operator

Next question comes from Paul Diamond with Citibank. .

Paul Diamond

Just wanted to touch back on FT optimization. So in your path to the initial 300million has been kind of quick into the point, the additional, I guess, 55 you see in 27, 28, I guess, is that expected to be more chunky? Or will it be a bit more taken in time here and there? I guess how do you see that [indiscernible] that coming through? .

Brendan Krueger

Yes, I think you'll see that play out 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..

Paul Diamond

Got it. Understood. And then just actually sticking on the FT optimization beyond 2018. I know you guys talked about doubling the current plan or additional $300 million, I guess, is that more on just FT like contract role? Or should we think about more optimization or sales or more like actionable moves?

Brendan Krueger

Yes. I mean the easy way to think about it is 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 better upwards of $1.35, $1.40 back of Henry Hub. But 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 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 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. So we're not even assuming you're -- we're going to keep the good FT that goes to the strong LNG pole -- 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.

Operator

Your next question comes from John Abbott with Wolfe Research.

John Abbott

First question is, in your opening remarks, you just talked about the premium being paid for core acreage and how it's a windowing amount of doing amount -- how does that change your thoughts about potential M&A from either both a buyer or a seller perspective? Is more scale necessary since we're seeing more consolidation?

Michael Kennedy

For a buyer of acreage and 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. And we are the builder industrial builder of Northern West Virginia. So we are the consolidator of West Virginia acreage. So that gives us an advantage -- it is scarce, but we do surround a lot of the acreage now. So we're probably the only buyer of a lot of this, our only logical buyer. And there's a lot of efficiencies and synergies that we can value. So that makes us a likely consolidator of the [indiscernible].

John Abbott

Appreciate it. And then when you see this sort of spike in NGL pricing in 2020, Stephan, 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? Do you think -- 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?

Michael Kennedy

Yes, we're opportunistic depending on where the market's at. Generally, when we have buybacks at the time, it's on like 10b5-1 plans and we set in motion a buyback at a share price relative to propane, natural gas price or it's kind of a 2 or 3 factor equation. So we assess that every quarter. We look at where we're at versus kind of where the commodities are at, where our free cash flow is out of our debt at where our M&A opportunities are at and set it then. So we're highly opportunistic. We're very -- this year, we're happy that we were able to buy in over the last kind of 5 quarters -- or 5 million shares. We hope to continue to do that. At these levels, the opportunity seems to be there.

Operator

Your next question comes from John Annis with Texas Capital.

John Annis

For my first one, the [indiscernible] 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? And then looking ahead, what additional levers do you see to drive further gains?

Michael Kennedy

Yes. Well, we brought a 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 when we brought our operations team, which is the best in the business to do it. an easy 1 to look at is HG was doing 3 or 4 stages per day of completions. We do 13 to 14. So that's always going to lend itself to a lot of efficiencies the drilling days 2 were sub 5 days per 10,000 feet. They were double digits on that metric. So just those 2, it's a lot of just bringing our practices to those assets, and we've done that. So -- that's how we've been able to achieve those.

Those have been ahead of schedule on the synergies. I think we said $75 million. We're well in the triple digit and that over $100 million for the year on that those will continue going forward.

John Annis

Got it. And for my follow-up, I think 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?

Michael Kennedy

Well, it's both. The benefit that we have is, I think, in 1 of the colors, we have 30 pads, I think I said it's exactly 28 pass. 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 were able to pick the best ones, capture the highest margins in the ones that may not be as margin-enhancing replace those with those local firm sales or local natural gas sales agreement. So we're in a great position.

Operator

Your next question comes from Josh Silverstein with UBS.

Joshua Silverstein

Outside of the sales -- potential sales agreements, we're -- 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 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?

Michael Kennedy

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

Joshua Silverstein

Got it. And then new 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.

Michael Kennedy

Yes, significant economic enhancements. I think next year, our drilling is going to average 18,000 feet, which is a record. I think this year made 15 and 16, we completed the 25. You had 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 in the next go over 30,000 the goal. So we'll continue to push and push and -- the beauty of HD and now our Eastside expressed the development of that 100,000 of undeveloped natural gas acres as we can perfectly plan it -- and I think you touched on the number, you get 5 wells going north 20,000 feet, on south, 20,000 feet. And that seems to be the perfect plan with 1 high-pressure pipe going through the middle of a row of hundreds and hundreds of locations. So that's where we're headed and to optimize that. And I think you'll see that in the coming years. .

Operator

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.

Daniel Katzenberg

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.