タンボラン・リソーシズ（TBN）2026年度第4四半期決算説明会：ビータルー・ガス初の販売

主なポイント

• タンボラン・リソーシズ（Tamboran Resources）は、ビータルー盆地からノーザンテリトリー市場への初のガス販売を開始しました。電話会議の時点でガス供給は20日間続いており、季節的な需要の影響によりノミネーション（要請量）は1日あたり25テラジュールに制限されています。
• 試運転（コミッショニング）終了後、ガス売買契約（GSA）は1日あたり40テラジュールを対象とするテイク・オア・ペイ（受渡義務付き）供給期間に移行する見込みです。試運転期間中、供給は中断可能であるため、タンボランが受領するガス価格は契約価格の75%となります。
• SS-2水圧破砕（刺激）キャンペーンでは、横穴長3万フィートにわたり178ステージを完了し、1日で12ステージという同盆地での最高記録を樹立しました。このうち10ステージでは、現地で調達したビータルー・レッドサンドが使用されました。
• 経営陣の試算によると、輸入砂と比較して現地産の砂を使用することで、横穴長1万フィートの井戸1つあたり400万ドルの完工費用削減が見込まれます。より広範な採用は、長期的な生産データ次第となります。
• タンボランの当四半期末時点の現金残高は2億2,500万ドル、未引き出し融資枠は3,100万ドルでした。Daly Waters Energyからの条件付き受領金1,500万ドルを含めたプロフォルマ（試算値）ベースの現金残高は2億4,000万ドルとなりました。
• スターツ・プラトー圧縮設備は予定通りに完成し、予算予測を約900万ドル下回りました。現在、試運転と設備の最適化が進められています。

主要財務データ

タンボランは、試運転が続く今後の2四半期において、パイロットプロジェクトの収益および費用の一部が米国会計基準（U.S. GAAP）に基づき資産計上（資本化）される可能性があると述べています。その結果、短期的には損益計算書上の実績に関連するキャッシュフローの動きが反映されない可能性があります。

事業および操業実績

初のガス販売は、ビータルー盆地パイロットプロジェクトが商業供給へと移行したことを示しています。現在の供給量は、公表されている井戸の生産能力ではなく、ノーザンテリトリー政府のノミネーション（要請量）によって制限されています。タンボランは継続的な生産実績および減退率データを蓄積するために2つの井戸を優先しており、その他の井戸はフラックバック水（水圧破砕回収水）の回収とノミネーションに対応するため必要に応じて巡回運用されています。

SS-2パッドの水圧破砕（刺激）プログラムではリバティ・エナジー（Liberty Energy）の設備群を使用し、横穴長3万フィートにわたり178ステージを完了しました。ジッパーフラック手法により最大20時間の操業が可能となり、1日12ステージという同盆地での最高記録を達成しました。また、タンボランとリバティは水圧破砕およびワイヤーラインサービスの延長に関する法的拘束力のない覚書（MOU）を締結しました。リバティは2027年以降、より低排出な圧送設備の導入を開始する意向です。

SS2-5H井の10ステージではビータルー・レッドサンドが使用されました。経営陣によると、圧送圧力や亀裂発生への悪影響はなく、トレーサー結果でも隣接ステージと同等のパフォーマンスが示されました。タンボランは、井戸全体での使用を検討する前に、SS-1パッドで追加の部分的井戸テストを計画しています。

SS-1パッドでは、3本の掘削キャンペーンのうち最初の2本が完了し、3本目の掘削が進行中です。ビット設計の改善、制振ツール、掘削リグの改造により、モローク（Moroak）層での過去最高の掘削速度と横穴区間での平均掘削速度の向上が達成されました。経営陣は、タンボランが過去に24日間で掘削した実績に触れ、25日以下の掘削期間は現実的であるとみています。

東部デポセンター（堆積中心部）では、サントス（Santos）がEP 161においてジベラ・サウス1H（Jibera South 1H）およびニューカッスル・サウス1H（Newcastle South 1H）評価井の掘削を開始しました。タンボランは25%の操業参加権益（ワーキング・インタレスト）を保有しています。Bシェールが引き続き主要ターゲットですが、他の区間でもさらなる重複油気層（スタックドペイ）の可能性が確認されています。

経営陣の見通し

経営陣は、雨季の気温上昇と電力需要の増加に伴い、ノーザンテリトリーのガスノミネーションが増加すると見込んでいます。タンボランは、顧客需要の時期によるものの、年末までにノミネーションが契約水準である1日あたり40テラジュールに近づく可能性があると述べています。翌年には季節的な制限が再び発生し、一部の追加井戸をオフライン（停止）にする必要が生じる可能性があります。

試運転および生産テストが完了すると、タンボランは供給が1日あたり40テラジュールのテイク・オア・ペイ期間に移行すると見込んでいます。引取手が引き取らなかったガスは、将来の供給に備えて貯留（バンク）されます。

同社は、11月の2027年度第1四半期決算発表時に初の四半期ガス売上高および収益を計上する予定です。同社は2027年度および2028年度のキャンペーンにおいて、Daly Waters Energy、INPEX、サントスとともに今後18ヶ月間で少なくとも6本のステップアウト井（評価井）を含む、両ビータルーデポセンター全体の資源評価に注力する計画です。

より広範な設備投資プログラムは、戦略的パートナーの選定および関連する作業計画での合意に一部依存します。経営陣は協議が進行中であると述べたものの、取引のタイムスケジュールについては言及しませんでした。

リスクと重点領域

• タンボランのどの井戸も生産実績が90日未満であり、長期的な減退率や回収率の見通しは限られています。
• ビータルー・レッドサンドは初期の圧送およびトレーサーテストで期待通りの性能を示しましたが、貯留層のストレス変化に伴う耐久性を検証するには、より長い生産実績が必要です。
• 現在の販売量はノーザンテリトリー政府のノミネーションに依存しており、テイク・オア・ペイ供給が始まるまでは季節的な需要変動の影響を受けます。
• スターツ・プラトー圧縮設備の拡張は、周辺の第三者パイプラインインフラが追加の市場へ増産分ガスを輸送できるという確証が得られるかどうかに依存しています。
• 将来の設備投資の時期および規模は、引き続き戦略的パートナーとの交渉ならびに開発の優先順位に関するすり合わせと密接に関連しています。
• 豪州東海岸での拘束力のあるガス売買契約の締結には、より明確な資源評価と地下リスクのさらなる低減（デリスク）が必要になると予想されます。

アナリスト質疑応答のハイライト

アナリストは掘削効率、井戸の減退データ、現地産砂の拡張性、設備投資、パイプライン開発に注目しました。

経営陣は、掘削性能の向上要因として、再設計されたビット、制振ツール、改定された傾斜掘削計画、掘削リグの温度管理の改善を挙げました。低コストなシェール開発へと移行するための主な要件として、作業の反復、安定した作業員の確保、盆地全体でのアクティビティ活性化が提示されました。

生産に関して経営陣は、優先されている2つの井戸が期待通りのパフォーマンスを示しており、満足のいく圧力データが得られていると述べました。主な課題として残るのは、経時的な生産減退の挙動です。ノミネーションの増加に伴い追加の井戸が寄与する可能性がありますが、持続的な長期的パフォーマンス履歴の獲得において優先されるのは2つの井戸のみとなる見込みです。

タンボランは、十分な生産データが得られるまで井戸全体で現地産砂を使用する計画はありません。同社は、貯留層圧力が低下する中でレッドサンドを使用したステージが相対的な寄与度を維持できるかを評価する予定です。性能が同等を維持できれば、現地産砂が最終的に同盆地で使用されるプロッパント（支持砂）の実質的にすべてを占める可能性があると経営陣は述べています。

東海岸のインフラに関して経営陣は、APAグループが許認可および通行権の取得作業を進めていると述べました。ただし、拘束力のある商用契約の締結は、より明確な資源基盤を確立する追加の生産データおよび評価結果を待ってからになると見込まれます。

決算説明会 文字起こし全文

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 Tamboran Resources Fourth Quarter Fiscal Year 2026 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. [Operator Instructions] It's now my pleasure to turn the call over to Todd Abbott, Chief Executive Officer. Todd, please go ahead.

Todd Abbott

Hello, everyone, and welcome to Tamboran Resources Financial Year 2026 Fourth Quarter Earnings Presentation. My name is Todd Abbott, and I'm the Chief Executive Officer of Tamboran Resources. I'm joined here today by Chief Financial Officer, Eric Dyer; and VP, Investor Relations and Corporate Development, Chris Morbey.

I'll start by reviewing delivery against the commitments we made 12-months ago, then cover production and commissioning as we build towards plateau rates and contracted supply. I will also discuss what our latest well results and operating improvements mean for our performance and cost as we continue to derisk our asset. I will then review our funding position and close with the next development milestones before we take your questions.

Moving to Slide 2, you can see our disclaimer, which relates to forward-looking statements within the presentation. I encourage you to review those at your convenience.

On Slide 3. The last few months have been a pivotal period for Tamboran and the Betaloo Basin as we have delivered on a key commitment and provided the next step in derisking the basin. We have delivered First Gas Sales from the Betaloo to the Northern Territory Gas market. Homes and businesses in Darwin are now being powered by a local onshore resource. These gas sales also bring royalties to the Northern Territory Government and native title holders alongside job opportunities for Territorians. Tamboran already employs a significant local workforce, which we expect to grow as activity increases over the coming years.

Moving to Slide 4. Gas has now been flowing into the market for 20 days. Volumes are currently limited by market demand with the Northern Territory Government nominating 25 terajoule per day as the territory comes out of its lower demand season. We expect demand and therefore, nominations to keep growing through the Northern Territory's peak demand period. We are currently in the commissioning period of the Gas Sales Agreement. Once the agreement moves into the supply period, take-or-pay provisions will apply to the 40-terajoule per day contract quantity, and we will be getting revenue based on that 40-terajoules per day. Any gas the offtaker does not take will be banked for future potential delivery. This gives us downside protection in the event of lower nominations during the contracted period.

Regarding our flowback strategy, we will prioritize 2 wells to ensure that we're generating long-term production and well performance data to further derisk the basin. The remaining wells will be managed as needed to recover flowback water and to close any gap to the allowable nominations. In achieving this first gas milestone, our operations team have been working deliberately across multiple work streams. They successfully completed the stimulation campaign on the SS-2 pad in the Betaloo Basin. The program utilized the Liberty Energy stimulation fleet that was imported into the basin in 2023. During the program, we completed 178 stages across 30,000 lateral feet. It was the largest stimulation campaign conducted in the basin. And the Zipper-frac approach allowed us to achieve 20 hours of operations and the Betaloo Basin record 12 stages completed in a day. This gives us and the market early evidence that we can execute completions more efficiently.

The next measure of success is sustaining an improved pace across a full campaign, reducing downtime and bringing down completion cost per well.

We have also entered into a nonbinding memorandum of understanding with Liberty Energy, setting out the intent to extend the hydraulic fracture stimulation and wireline services agreement covering Tamboran's operations in the Betaloo Basin. Liberty intends to begin phasing lower emissions pumping equipment into the Betaloo fleet from 2027. Importantly, the campaign included 10 stages using the locally supplied Betaloo Red Sand across various locations in the SS2-5H well. The pumping and placement of the local sand was an identified risk going into the program. However, given we experienced no impact to pump pressures or fracture initiation during these stages, we are confident on our ability to place local sand in future campaigns. Tracers across the horizontal length have shown that the stages are producing in line with offset wells, but these are still early days, and the true test will be the longer-term flow rates and recoveries. We plan to further test our Betaloo Red Sand during the upcoming stimulation program planned on the SS-1 pad. Success of that local sand is a key step in delivering near-term cost reduction for well completions. It is expected that, that sand could save USD 4 million per well with a 10,000-foot horizontal section compared to the sand imported from overseas. Those long-term flow rates and recoveries from those stages will help us assess how widely we can apply those savings.

In conjunction with the upstream activity, the operations team successfully completed construction of the Sturt Plateau compression facility, on time and approximately USD 9 million below the forecasted budget. This allowed us to meet our commitment to the supply of the Northern Territory gas market during the quarter. The commissioning of the facility remains ongoing as we fine-tune control systems and refine equipment settings. During the commissioning period, we will be receiving 75% of the gas price. This is due to the interruptible nature of the supply. Once commissioning and production testing requirements are complete, we will commence delivery into the take-or-pay contract with the Northern Territory Government.

During the quarter, the operations team also commenced drilling the 3-well campaign on the SS-1 pad with the H&P Flex 3 Rig. Drilling of the first 2 wells has been completed with the third well currently drilling ahead. We continue to incorporate lessons from previous campaigns. This program includes first wells drilled with our improved drill bit design and anti-vibration tools. This resulted in record speeds through the Moroak formation. Modifications to the rig have resulted in reduced mud temps, allowing increased average ROP in the lateral sections. We continue to work with our contract partners to improve efficiencies and reduce downtime, especially within the lateral section, and we believe these are addressable as we ramp up activity.

In the East, drilling of the 2-well appraisal program with Santos on EP 161 has also commenced with the Jibera South 1H and Newcastle South 1H wells in that depocenter. During the quarter, we significantly strengthened our balance sheet. In April, we raised USD 186 million net of fees via an underwritten public offer and an institutional and retail entitlement. The funds from the raise solidify the balance sheet and provide us financial flexibility.

At the end of the quarter, Tamboran had USD 225 million in cash and USD 31 million in undrawn debt for funding of the SPCF, including the USD 15 million that we expect to receive from Daly Waters Energy, the pro forma cash position is USD 240 million. Receipt of that $15 million remains subject to certain conditions precedent. Over the next 2 quarters, we expect that under U.S. GAAP, some revenue and costs related to the Pilot Project will be capitalized to the balance sheet during commissioning, rather than flowing through the income statement. This is to avoid reporting volatility and means that the income statement will not reflect cash movements during the period. We expect to announce first quarterly gas sales and revenue in our 1Q fiscal '27 earnings in November.

The next phase of our development plan is to further delineate our gas resources across both depocenters in the Betaloo Basin. This will be the focus of our '27 and '28 campaigns. We are working with our joint venture partners, Daly Waters Energy and INPEX in the West and Santos in the East to drill and stimulate at least 6 step-out wells over the next 18 months. We are progressing discussions with multiple parties to bring in a strategic partner. These strategic discussions and the upcoming appraisal work, aims to align on resource delineation and commercialization pathways that will support a large-scale development and underpin new pipeline infrastructure. That infrastructure is expected to connect the Betaloo Basin to multiple high-value markets.

To close, we have delivered the First Gas Sales that we committed to 12 months ago and completed the compression facility on time and below the forecasted budget. Our latest drilling and stimulation work is showing where we can improve efficiency, while local sand offers a potential source of completion cost savings. The equity raise has strengthened our balance sheet for the next phase of development. The priority now is to turn those achievements into sustained operating performance. That means completing commissioning and production testing, building towards plateau production and contracted supply and demonstrating that the gains in well delivered can be repeated. Those are the measures, I will use to judge our progress as we advance our development plans and partner discussions.

As we close, I want to thank all Tamboran employees for their commitment, their performance and their support for one another as we continue to grow, evolve and deliver for our customers and shareholders. Thank you.

Operator

[Operator Instructions our first question today is coming from Scott Hanold from RBC Capital Markets.

質疑応答

Scott Hanold

Congrats on all the milestones that you guys have achieved and plenty ahead. I want to start maybe focusing on the SS1-6H well. It sounds like it was a pretty successful drill and -- could you give us a sense of what specifically you're changing in your drilling operations to see that success? And what other knobs and dials are you looking forward to doing? And I'm sorry, I'm going to layer on one more thing on this. What kind of cost -- what is that kind of pro forma cost on that now that you've seen some good improvement?

Todd Abbott

Yes, Scott, good to hear from you. Good question. On the 6H and maybe even more broadly kind of on the total drilling program, like the recent changes you'll see there, and I referenced it in the remarks there, the bit design on some of the kind of upper level zones there that we were going through. The vibration damper was actually a pretty big change for us. So that's helped us quite a bit.

I'll also add like one of the things that isn't really a tool change, but the directional plans on those wells and that the way we attack that Moroak Sandstone, which is just a really hard zone, just hard rock to get through. So that's been one of the areas where we saw the biggest opportunities. And in that last well, we got through it with one bit, which was a big win for us. Earlier wells, initial wells on this had many more bits trying to get through that zone. So that's been a key improvement for us. When we look at the kind of opportunities going ahead, we think improving time on our downhole tools is going to help us a lot. We do see opportunities eventually to go to a synthetic oil-based system, which will help our drilling times as well, the ROPs.

And then there's going to be a lot of little things. I mean, I think you've heard me say this before, ultimately, to really get the drilling times and those costs down where we need them to be, we need two things. We need repeatability. So just doing the same thing, same crews, doing it again and again and again. And then the other is scale across the basin. So this is all operators, but having enough critical mass of activity in the basin so that service companies have their center of operations that can be efficient in the way they set up their operations, so that we have readily available tools, readily available people, skill sets, logistics all work better. Everything we've seen in these large shale plays in the U.S. will eventually happen here. But those are the two things that really get it down into those kind of U.S. level cost structures.

Scott Hanold

Good to hear that. My follow-up question is -- and correct me if I'm wrong, it sounds like there's two of the wells that are producing online at this point in time. And could you give us a sense of what you've seen? I know it's still early, but what have you seen on the pressure data on those wells? And are those wells kind of -- have you opened the choke up fully on those? Or are they still choke back here at this point?

Todd Abbott

Yes. I'll say it's been variable on that. The wells look good. They're in line with our expectations. What we're really interested to see on those are the long-term decline rates, and won't know that for a bit. And we haven't produced a well out here for more than 90 days. So specifically, we're working under that 25-terajoule a day nomination limitation. So we're prioritizing 2 wells so that we can develop the production histories and the well performance data to show what the wells can do. But aside from those 2, we've had the other wells cycling on and off kind of as needed, if we need to close the gap to the denomination or as we need to manage getting water off of those wells, kind of helping clean those up. With regard to pressure data, I mean, the pressure data looks good. But again, it's kind of all in line with our expectations. We just need to watch that over time.

Operator

Next question is coming from Leo Mariani from ROTH.

Leo Mariani

I was hoping you maybe talk to what you think CapEx is going to be in the rest of the calendar year. So I guess it would be calendar 3Q and 4Q? Just trying to get a sense of that would be helpful.

Todd Abbott

Yes. And we'll get Chris to kind of go through the specific numbers on it. But I'll tell you, at a high level, we've got 4 wells in the Pilot Area that you'll see 3 this year, 1 next year. We've got the 2 Santos wells over EP 161 with our 25% working interest drill this year, stimulating next year. And then we've got the 4 wells in the BCDA with Daly Waters. It's about a 10% working interest there. So I mean, overall, you can expect our capital to be focused on derisking.

And frankly, the full capital program isn't going to be fully locked-in until we finalize who our partner is and align those, what I would call, collective strategic priorities, kind of where we're going to be in both basins. As you can imagine, each potential partner has a little bit different focus, either one depocenter or the other or for some both. So as those conversations evolve, we'll lock the rest in.

Leo Mariani

Okay. And can you provide a little bit more color on kind of where you are in the process of securing a partner? Do you think that's likely to happen kind of in the next handful of months, which will let you kind of give a better picture of what that kind of '27 calendar year budget would be?

Todd Abbott

Yes, it's certainly moving forward. Look, we continue to see strong outside interest. We're having the right conversations with the right potential partners. I mean, at the end of the day, we're looking for the right capabilities to fit with the strategy and the right time frame with the operation. So I can sympathize with the kind of desire for certainty on the time line, but just please bear with us. It's all in play. And I'm sure everyone appreciates that deals like these take time and need to be carried-out thoughtfully. So we're working through that process. It will -- wherever we land on that, whichever partner we ultimately land with, it will be with a defined work program. And going back to your first question, that will update that capital program.

Operator

Next question is coming from Jeff Grampp from Northland Capital Markets.

Jeffrey Grampp

I was curious with respect to additional in-basin sand testing, I think you said the upcoming fracs will include at least 1 well. I just wanted to clarify, is that something you guys are comfortable doing across the whole wellbore? Will this be another partial test? And then maybe just taking a step back, what do you guys view as kind of the scalability of in-basin supply to the extent you have more confidence there? How meaningful of a portion of the program could that be longer term?

Todd Abbott

Yes. So first, I'll just kind of talk about the early performance. And I mentioned in the remarks, too, we had no problems pumping the sand, which -- that was something we were watching for. We started the fracs, like initiated the fracs well with it. So we're highly confident in our ability to pump it. When we look at the tracers coming back from those stages, they look identical to the other stages and the other wells. So early results are positive. But just like with the production, we won't know the full answer until we get some production history on this and see how all that holds up. So yes, we're optimistic on what it can do.

With regard to these next wells, we won't move to a full Red Sand program until we are confident in it. So we need some of that history. Each well we drill out here is pretty important to help derisk the basin. So we're not going to kind of take outsized risk on any one of them. So we'll do some additional stages on these next completions, but we won't do full wells at this point, Jeff. Going forward, like once we get history on it, once we're comfortable that the Betaloo Red Sand does what we expect and hope it will do, I can see us going to a 100% full program of Red Sand or effectively 100%. There could be some supplements here and there. But I think the end goal is to use in-basin sand in the Betaloo. And from a well cost perspective, it's going to be the obvious right thing to do.

Jeffrey Grampp

Yes. Understood. That makes sense. And for my follow-up, with respect to the potential to expand the SPCF, I think you talked about maybe making an investment decision next year. What are the milestones or key, I guess, check boxes, if you will, to get comfortable making that decision? Is that more on comfortability around your own internal producibility volumes, offtake, financing, all the above? Just any kind of, I guess, kind of milestones to keep an eye out to track that project?

Todd Abbott

Yes. I think all the things you're mentioning are important inputs on it, although I feel pretty good about all the ones you mentioned. The one that we really have to look at, and this is probably the key uncertainty on whether we expand it or not, is making sure that the surrounding infrastructure network will allow us to move the incremental volumes to the incremental markets, right? Just having high confidence that we can get that.

We don't own the pipelines all around us and understanding how the gases are going to flows and how those are going to be upgraded or modified over time will help us make the decision. So we're working through that now, kind of getting a better understanding each day on it. But that's something we just need certainty on before we make that kind of investment. We need confidence that we will be able to...

Operator

Next question is coming from Charles Meade from Johnson Rice.

Charles Meade

Good morning Todd to you, and Eric and Chris and the rest of the Tamboran team. Todd, I want to go back to the -- your decision to flow these -- or really, I guess, prioritize these 2 wells in the initial 25 million cubic feet a day. It seems like getting more production history on more wells is the -- one of the key near-term things that you're looking for. So I'm curious, can you give us an idea when that 25 million cubic feet a day will go to up to the 40 million cubic feet? I mean, I think you said it's contingent on the full commissioning of the SPCF. Can you just give us a time line on when you're going to be able to start to build more of that production history?

Todd Abbott

Yes. Charles, just to make sure I understand your question. You're asking when can we get like -- it's about 25 terajoules now, but when can we get up to the 40 terajoules take-or-pay?

Charles Meade

Yes. And presumably, if you're doing it from 2 wells now, then when you get to 40 terajoules, then you're doing 3 or perhaps even 4 wells. And I guess I didn't do a good job asking the question, but it seems like the data that everyone wants to see are these decline curves. And so when are you going to be able to start building not 2 decline curves, but 3 or 4?

Todd Abbott

Yes. Okay. I understand your question. So yes, on the nominations, right? So the NTG, the Northern Territory Government nominates the gas that they need, right? So right now, because of just where they are seasonally, those needs are not high. So they've limited us to 25 terajoules a day for most days. That will continue kind of in the near term as they move into the wet season, as temperatures rise, you're going to see that load increase, their power generation load increase and thus their gas demand increase.

But just to be clear, I think I said this clearly earlier in the remarks, but not exactly your question, Charles, but for everyone else's benefit, the 25 terajoules a day is a Northern Territory Government limitation, not a well [indiscernible]. So we're meeting that now. We prioritized the 2 wells. Exactly what you're saying, our priority is on generating well history and performance data for these wells long term. So we prioritized the 2 wells. We expect as we move through towards the end of this year, that nomination is going to go up. We're going to get more wells under that.

But to start with, we're prioritizing those 2 wells. And the wells we're prioritizing are both full 10,000-foot lateral and then the well with Betaloo Red sand so that we can get clarity on that data. I think probably by the end of the year, we'll see up with that -- I'm kind of predicting a little bit what they're going to nominate that 40 terajoule a day target. So we'll be able to get more wells in there, Charles, but it's hard to say exactly.

But then later, as we go into next year, we should expect the seasonal restrictions to kind of come back in, and we'll have to pull some of those incremental wells offline. So you won't get the full kind of 12-month history on the other wells, but we are going to prioritize at least 2 wells, so that we can really see the long-term history of what the wells do. Am I answering your question? I feel like I muddled through that.

Charles Meade

No, no, no, you did. That's a great elaboration. And you understood what I was asking even if I didn't make it very clear on my part. But -- and then separately, going in a different direction about the derisking more of the basin. These 2 wells that -- these 2 Santos-operated wells off to the East, can you remind us, I mean, you've shown these logs on Page 12, and it looks thicker over there. You've got multiple landing guards. Can you remind us where -- which of these shale zones you have the laterals targeted-in? And also, can you remind us which of these zones did you test vertically way back in 2021 with that Tanumbirini?

Todd Abbott

Yes. So on the east side, just like the West side, the primary target is the B shale. And if you look on those logs, yes, you can see they vary a little bit, but what you'll see common in both logs is the B shale is the primary target to most people when they will look at it, and both areas have multiple stack pay outside of the B shale, right? So whether you're looking at the A or the C or some of the other things in there. Going back to the history, I'll have to go back and look at the log to see exactly what that well test was. You're predating me a little bit, so I need to go back and check on that. Chris or Eric may hand in on whatever on top of mind...

Eric Dyer

Yes. I mean the -- so there was a vertical frac done by Santos, I want to say, 2019 that hit most of the zones and there was -- one of the lower zones was a bit tight. But look, there's a lot of prospectivity there. The B shale is by far the primary target. But there is some downhole potential and there is some opportunity. But really, that's all off of one vertical frac from 7 years ago. So I think capital is precious, and we've got to be very careful with what we're doing. We're working very closely with Santos to evaluate where we're looking at in that side of the basin. But I do think that, that's one of those things where, in time, there is potential.

Operator

Next question is coming from Paul Diamond from Citi.

Paul Diamond

Circling back to local sand. I guess I know you guys have run the tracer data and talked about 12-month curves being ideal. But I guess can you dig down a little bit there? What are you looking for in that data? I guess what's the hurdle rate on kind of the go or no go for using 100% sand on maybe the 6 wells in the next 18 months or if it's a longer-term narrative?

Todd Abbott

Yes. I mean I would say the real impact of the Red Sand is really in development mode, right, where your capital intensity is higher. We have more wells going in. So we certainly want to have that answer before we get into a development mode. We want to use increasing test as we go forward. What we're specifically looking for in this, is to make sure that the zones where we place that Red Sand hold up on a relative contribution basis over time. Right?

So you can see situations where as the reservoir drawdowns and as those stresses change downhole a bit, the crush pressure for that, that's not a technical term, but can kind of increase over time. We want to make sure that this sand holds up the way the other zones hold up. So that's what we're looking for. We're looking for relative contribution across those different zones and make sure they're comparable. And as long as they are, the cost differences are dramatic, we'll stay with the local sand.

Paul Diamond

Got it. And then switching to Slide 11. You guys show your kind of target of 25 days or less than 25 days. Just trying to get an understanding of, I guess, how -- I guess we're all trying to triangulate CapEx over the long term. But how do you -- how much lower do you think you can get over the course of the next, call it, the 6 delineation wells over the next 18 months? Is 25 days kind of the right number? Or is there a target below that?

Todd Abbott

I think 25 days is a very realistic number for us, and we've actually beat that on other wells, right? We've had a 24-day well. And if you look at our performance in the individual sections of those wells, you add all those up, they're well under the 25 days. On each one, there's kind of been little things here and there that have kept us from doing that, but we're starting to see exactly how we de-bottleneck those processes. So I think you'll see us continuing to improve those. Longer term, I think you could -- especially in the development mode, you should see us setting more ambitious targets than 25 days. But for where we are right now, I think 25 days, is a good target.

Operator

Next question is coming from Anish Kapadia from Hannam.

Anish Kapadia

Just had a question, first of all, in terms of -- I just want to see what needs to happen before the non-binding LOIs that you have for the pipeline get converted into binding GSAs? And when do you realistically expect that conversion to begin? And kind of related to that, what are the remaining commercial regulatory financing milestones for the East Coast pipeline? And what's the kind of current timetable for that binding pipeline development agreement and FID?

Todd Abbott

Yes. So your question is specifically East Coast?

Anish Kapadia

Yes.

Todd Abbott

Okay. Yes. Look, I think APA has been out there pretty actively talking about their work on the East Coast pipeline. They've done a lot of work on both the permitting side and the right-of-way acquisition or [ reason-in ] acquisition to get that and are fairly well progressed. So high confidence that's moving to their credit. They're not really waiting. They're charging ahead on it. From a sequencing standpoint, the way I see that developing is this.

You'll see additional work, like the production data that we're putting on the board from the Pilot Area is probably the biggest piece of information to derisk the subsurface. That's what everybody and kind of everyone on this call and everyone within Tamboran are waiting to see. But that will demonstrate the well decline and the longer-term nature of these wells. Then you've got the other wells that are going in this year.

So the 2 wells over EP 161 are going to be important. The other wells in the West will also correlate. Then over time, and kind of referencing this with our JV process again, there will be other work programs that come out and delineate additional resource. But ultimately, what the industry has to do, and I say that meaning broader than just Tamboran is collectively our work will derisk the resource to merit that infrastructure investment. And that can happen fairly quickly. The resource out here is such that it doesn't take a lot of wells to identify pretty large resource and to merit that large infrastructure investment. So that East Coast pipeline with APA doing their work and with us doing the upstream work, it really derisk the investment.

And we all know that the LNG for this on the East Coast and the new both in the domestic market and in the LNG facilities over there. So GSAs, early conversations are already happening, but there's nothing binding that's going to happen until you have a very clear resource. So I hope that's helpful. That's kind of where the sequence is. It's a little bit hard to say exactly what the timing looks like, but that's the way the sequence will work.

Operator

We reached the end of our question-and-answer session. I'd like to turn the floor back over for any further or closing comments.

Todd Abbott

Listen, guys, we always appreciate the conversations. We're excited about where we're going. We are fully focused on strategically de-risking this play. That's the most important work ahead of us. So the production data is going to go a long ways towards that and then some further delineation work in '27. And I think it's going to be a big year for the basin. So thank you for your engagement, and we'll keep moving on.

Operator

Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time, and have a wonderful day. We thank you for your participation.