アンテロ・リソーシズ（AR）2026年第3四半期決算説明会：過去最高の生産量とNGLのアップサイド

アンテロ・リソーシズ（NYSE: AR）は、2026年第3四半期の生産量が過去最高を記録し、現金コストが低下したと発表しました。同時に、NGL（天然ガス液）価格の上昇と輸送の最適化が、今後のフリーキャッシュフローの主な牽引役になると強調しました。

主な要点

• 当四半期中に1日あたり1億MMcfe（100 MMcfe/d）を超える減産が行われたものの、生産量は前年同期比23%増の1日あたり4.2 Bcfe（4.2 Bcfe/d）となり、同社としての過去最高を記録しました。
• 総現金コストは前年同期比16%減少して同社史上最低水準となり、天然ガス価格が4%下落したにもかかわらず、未ヘッジEBITDAXマージンは1 Mcfeあたり0.27ドル（27%）増加しました。
• アンテロは当四半期中に160万株の自社株買いを実施し、2025年年初以降で発行済株式数を500万株以上削減しました。
• 同社は、年間3億ドルのマージン向上目標のうち、1億4,000万ドルを2027年半ばまでに実現する見込みです。経営陣は、2030年代前半までにこの機会が当初目標の約2倍に達する可能性があると述べました。
• 経営陣によると、第4四半期のNGL価格は第3四半期の水準を50%上回って推移しており、スポットC3+の実現価格は1バレルあたり60ドルを超え、2022年以来の最高水準に迫っています。
• アンテロはリグ3基および完井クルー2組による開発プログラムを維持する計画です。経営陣は、2027年の生産量が2026年の平均生産量と比較して1桁台後半の成長を示すと見込んでいます。

主な財務データ

業績および事業展開

アンテロは生産量の拡大について、HG社の買収および総生産ベースでのワーキング・インタレスト（操業権益）を引き上げた取引によるものとしています。経営陣は、HG社の操業シナジーが当初目標の7,500万ドルを超え、年間で1億ドルを突破したと述べました。

同社は、買収した資産における掘削および完井の大幅な効率改善を挙げました。完井の生産性は前オペレーター時代の1日あたり約3〜4ステージから1日あたり13〜14ステージに向上しました。掘削パフォーマンスも、従来の10,000フィートあたり10日以上から5日未満へと短縮されました。

アンテロは当四半期中、過去最長となる約25,000フィートの水平坑井（ラテラル）を完井しました。経営陣は、2027年には平均水平長が約18,000フィートに達すると予測しており、将来の坑井では30,000フィートを超える可能性もあると述べています。

液状資源（リキッド）は引き続きマージンの重要な牽引役です。アンテロは年間約4,500万バレルのC3+ NGLを生産しており、同数量に対するヘッジを行っていません。経営陣は、この価格上昇が維持された場合、第3四半期の価格から1バレルあたり20ドル上昇すれば、年間で約9億ドル（四半期あたり2億2,500万ドル）のフリーキャッシュフローの追加創出に相当すると述べました。

同社は、C3+価格が1バレルあたり60ドルを超えたことを受け、1,300 Btuのバーナット（Barnat）リッチガス（液状成分の多いガス）パッドの完井を進めています。長期的な開発ミックスは、NGL開発へ大きくシフトするのではなく、ドライガス・パッドとリッチガス・パッドの間でバランスを維持する見通しです。

マージン向上および輸送戦略

アンテロは2027年半ばまでに年間1億4,000万ドルのマージン向上達成を見込んでいます。主な内訳は以下の通りです。

• 2026年7月1日付で発効する2020年のオーバーライディング・ロイヤリティ（過剰鉱区使用料）権利取引に基づき、キャッシュフローの85%が還元されることによる、年間6,000万ドルのフリーキャッシュフロー創出効果。
• 1日あたり1 Bcf（1 Bcf/d）の確定輸送能力（ファーム輸送容量）の最適化による、年換算で約5,000万ドルのフリーキャッシュフロー改善。この目標には、第3四半期に締結された400 MMcf/日分の契約が含まれます。
• 2027年第3四半期に出来高連動型生産払い（VPP）取引が終了することによる、年換算で3,000万ドルのフリーキャッシュフロー創出効果。

経営陣によると、当初の3億ドルの目標に向けた残りの道のりには、2028年に期限を迎える液状資源輸送契約からの約1億ドル、およびドライガス開発や地域プレミアム価格での販売契約からの約6,000万ドルが含まれます。

2028年以降について、アンテロは長期的かつ産地内（インバシン）での販売拡大とさらなる輸送最適化により、当初の目標額3億ドルが倍増する可能性があると見込んでいます。経営陣は、コストの高い輸送ルートを、地域指標に対しプレミアム価格がつく地域契約へ切り替える可能性に言及しました。

イースト・サイド・エクスプレス（East Side Express）パイプラインは、約10万エーカーの未開発ドライガス鉱区を7〜8箇所のパイプライン相互接続点と結ぶ予定です。経営陣は、このプロジェクトによって市場の選択肢が向上し、コミットメントを含む総輸送コストが削減され、電力・ガス会社やその他のエンドユーザーとの長期販売契約が後押しされると述べています。

業績見通し（ガイダンス）

経営陣は第4四半期の生産量ガイダンスを1日あたり約4.3 Bcfe（4.3 Bcfe/d）と発表しました。アパラチア地域の価格が採算の合わない水準に下落した場合には地元のドライガス生産を抑制する柔軟性を維持しつつ、よりマージンの高い液状資源の生産は継続します。

2027年について、経営陣は2026年の平均生産量と比較して1桁台後半の生産成長を見込んでいます。この見通しには、潜在的な生産抑制や、完井した坑井の稼働開始時期に関する柔軟性が組み込まれています。

同社はリグ3基と完井クルー2組を維持する意向です。資本投下は引き続き柔軟に行い、商品価格に応じて完井のタイミングを調整します。アンテロは、プロジェクトの採算性を保護するため、2027年と2028年向けに1日あたり1億MMcf（100 MMcf/d）を超えるリーンガスを約3.50ドルでヘッジしました。

経営陣は、追加の輸送最適化契約や地域向け天然ガス販売契約の発効に伴い、2027年の現金生産費用が低下傾向をたどると予想しています。商品価格の上昇に伴う燃料費の影響で第4四半期のコストはわずかに増加する可能性がありますが、事業の根底にあるコストベースは全体として安定しています。

リスクと注視すべき事項

• 9月と10月には、川下での障害によってアパラチア地域のガス価格が異例の安値まで下落しました。経営陣によると、一部の週末には約0.60ドルまで下落したため、アンテロはその価格で販売するのではなく地元のドライガス生産を減産しました。
• NGLの価格設定は、地政学的動向、原油価格、世界的なLPG供給、輸出需要の影響を受けやすい状況が続いています。経営陣は、ホルムズ海峡の混乱によって影響を受けた海上輸送LPG供給の約25%がまだ回復していないと指摘しました。
• 海上運賃の高止まりは、少なくとも2027年前半の輸出ネットバック（限界利益）を圧迫する可能性がありますが、経営陣は新造船の就航に伴い一定の緩和を期待しています。
• 生産量の成長は、完井のタイミングや減産の前提条件に一部依存します。天然ガスや液状資源の価格が低迷する期間、経営陣は坑井の稼働開始を延期する可能性があります。
• アンテロのマージン戦略により、一部の市場で報告される実現価格が低下する可能性がありますが、経営陣は輸送コストの削減がその影響を相殺して余りあると考えています。

アナリスト質疑応答の要点

経営陣は、季節的な需要低下や川下での障害のため、第3四半期の天然ガス価格差（デファレンシャル）が異例の拡大を見せたと述べました。第3四半期の価格差は約0.30ドルでしたが、第4四半期には約0.20ドルへと改善する見込みです。2027年について、経営陣は実現価格が地域インデックス並みになる一方、輸送コストの低下が純マージンを下支えする可能性があると示唆しました。

クラリントン（Clarington）市場において、アンテロは現在1日あたり約400 MMcf（400 MMcf/d）を供給しています。長期契約では、短期の販売で約0.10〜0.15ドルのプレミアムであるのに対し、M2ベンチマークに対して0.20〜0.25ドルのプレミアムを獲得できる可能性があります。経営陣は、同市場からの需要引き合いが推定1日あたり5〜6 Bcf（5–6 Bcf/d）あることを勘案すると、供給量をさらに1 Bcf/日増やすことは現実的であると述べました。

経営陣はまた、イースト・サイド・エクスプレスを利用して、1日あたり200 MMcf（200 MMcf/d）の輸送契約をM2プラス価格での販売契約に置き換えることによる経済的効果も強調しました。同社は、この規模の取引が1つ実現するだけで、年間7,500万〜8,000万ドルのマージン向上につながると試算しています。

資本配分について、アンテロは自社株買いを引き続き機動的（オポチュニスティック）に行い、商品価格、フリーキャッシュフロー、レバレッジ、潜在的な買収機会を総合的に評価して実施すると述べました。経営陣は、既存のアップストリーム（開発・生産）、ミッドストリーム（輸送・処理）、輸送基盤を有していることから、同社がウェストバージニア州の鉱区における集約（業界再編の主導体）となる可能性が高いと説明しました。

決算説明会（電話会議）全文文字起こし

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決算説明会の完全なトランスクリプト

経営陣による説明

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.

質疑応答

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.