Cuộc họp công bố kết quả kinh doanh quý 4 năm tài chính 2026 của Tamboran Resources (TBN): Lần bán khí đốt Beetaloo đầu tiên

Điểm chính

• Tamboran Resources đã thực hiện đợt bán khí đốt đầu tiên từ Bồn địa Beetaloo tới thị trường Lãnh thổ Bắc Úc. Khí đốt đã chảy được 20 ngày tại thời điểm diễn ra cuộc họp, với sản lượng đăng ký mua bị giới hạn ở mức 25 terajoule mỗi ngày do nhu cầu theo mùa.
• Sau khi vận hành thử nghiệm, Hợp đồng Mua bán Khí đốt dự kiến sẽ bước vào giai đoạn cung cấp theo phương thức bao tiêu (take-or-pay) với sản lượng 40 terajoule mỗi ngày. Trong quá trình vận hành thử nghiệm, Tamboran nhận được 75% giá khí đốt do nguồn cung có thể bị gián đoạn.
• Chiến dịch kích thích giếng SS-2 đã hoàn thành 178 giai đoạn trên 30.000 foot chiều dài ngang, bao gồm kỷ lục toàn bồn địa là 12 giai đoạn trong một ngày. Mười giai đoạn đã sử dụng Cát đỏ Beetaloo khai thác tại địa phương.
• Ban quản lý ước tính việc sử dụng cát địa phương có thể giúp giảm 4 triệu USD chi phí hoàn thiện cho một giếng có chiều dài ngang 10.000 foot so với cát nhập khẩu. Việc áp dụng rộng rãi hơn vẫn phụ thuộc vào dữ liệu khai thác dài hạn hơn.
• Tamboran kết thúc quý với 225 triệu USD tiền mặt và 31 triệu USD nợ chưa giải ngân. Bao gồm khoản tiền 15 triệu USD có điều kiện từ Daly Waters Energy, tiền mặt pro forma là 240 triệu USD.
• Trạm nén Sturt Plateau đã hoàn thành đúng tiến độ và thấp hơn khoảng 9 triệu USD so với ngân sách dự báo. Quá trình vận hành thử nghiệm và tối ưu hóa thiết bị vẫn đang được tiến hành.

Dữ liệu tài chính quan trọng

Tamboran cho biết một số doanh thu và chi phí của Dự án Thí điểm có thể được vốn hóa theo U.S. GAAP trong hai quý tới trong khi tiếp tục vận hành thử nghiệm. Do đó, kết quả báo cáo kết quả hoạt động kinh doanh trong ngắn hạn có thể không phản ánh các dòng tiền liên quan.

Kết quả kinh doanh và vận hành

Các đợt bán khí đốt đầu tiên đánh dấu sự chuyển đổi của Dự án Thí điểm Bồn địa Beetaloo sang cung cấp thương mại. Sản lượng hiện tại bị giới hạn bởi lượng đăng ký mua của Chính quyền Lãnh thổ Bắc Úc thay vì công suất giếng đã công bố. Tamboran đang ưu tiên hai giếng để xây dựng lịch sử sản lượng và tỷ lệ suy giảm liên tục, trong khi các giếng khác được vận hành luân phiên theo yêu cầu để thu hồi nước hoàn lưu và đáp ứng lượng đăng ký mua.

Chương trình kích thích tại cụm giếng SS-2 đã sử dụng đội ngũ của Liberty Energy và hoàn thành 178 giai đoạn trên 30.000 foot chiều dài ngang. Phương pháp nứt nẻ thủy lực đúp (zipper-frac) đã hỗ trợ vận hành liên tục lên tới 20 giờ và đạt kỷ lục toàn bồn địa là 12 giai đoạn trong một ngày. Tamboran và Liberty cũng đã ký bản ghi nhớ không ràng buộc về việc gia hạn các dịch vụ kích thích và đo địa vật lý giếng khoan (wireline). Liberty có kế hoạch bắt đầu đưa vào sử dụng thiết bị bơm phát thải thấp hơn từ năm 2027.

Mười giai đoạn tại giếng SS2-5H đã sử dụng Cát đỏ Beetaloo. Ban quản lý báo cáo không có tác động bất lợi nào đến áp suất bơm hoặc quá trình tạo vết nứt, trong khi kết quả chất đánh dấu cho thấy hiệu suất tương đương với các giai đoạn đối chứng lân cận. Tamboran dự kiến sẽ tiến hành thêm các thử nghiệm một phần giếng tại cụm giếng SS-1 trước khi xem xét sử dụng cho toàn bộ giếng.

Tại cụm giếng SS-1, hai giếng đầu tiên trong chiến dịch khoan ba giếng đã được hoàn thành, trong khi giếng thứ ba vẫn đang được khoan. Thiết kế mũi khoan cải tiến, các công cụ chống rung và việc điều chỉnh giàn khoan đã hỗ trợ tốc độ khoan kỷ lục qua tầng Moroak và tốc độ thâm nhập trung bình cao hơn ở các đoạn khoan ngang. Ban quản lý nhận thấy thời gian khoan từ 25 ngày trở xuống là thực tế, đồng thời lưu ý rằng Tamboran trước đây từng khoan một giếng trong 24 ngày.

Tại trung tâm trầm tích phía đông, Santos đã bắt đầu khoan các giếng thẩm lượng Jibera South 1H và Newcastle South 1H trên giấy phép EP 161. Tamboran nắm giữ 25% cổ phần tham gia (working interest). Tầng đá phiến B vẫn là mục tiêu chính, với tiềm năng chứa dầu khí đa tầng (stacked-pay) bổ sung được xác định ở các khoảng khác.

Triển vọng từ Ban quản lý

Ban quản lý dự kiến lượng đăng ký mua khí đốt tại Lãnh thổ Bắc Úc sẽ tăng khi nhiệt độ và nhu cầu điện tăng trong mùa mưa. Tamboran cho biết lượng đăng ký mua có thể tiệm cận mức hợp đồng 40 terajoule mỗi ngày vào cuối năm dương lịch, mặc dù thời điểm cụ thể phụ thuộc vào nhu cầu của khách hàng. Các hạn chế theo mùa có thể xuất hiện trở lại vào năm sau và yêu cầu tạm ngừng hoạt động một số giếng bổ sung.

Sau khi hoàn thành vận hành thử nghiệm và kiểm tra sản lượng, Tamboran dự kiến nguồn cung sẽ chuyển sang giai đoạn bao tiêu 40 terajoule mỗi ngày. Lượng khí đốt mà bên bao tiêu không nhận sẽ được tích lũy để có thể giao trong tương lai.

Công ty dự kiến sẽ báo cáo doanh số bán khí đốt và doanh thu hàng quý đầu tiên cùng với kết quả Q1 FY2027 vào tháng 11. Công ty có kế hoạch tập trung các chiến dịch FY2027 và FY2028 vào việc xác định ranh giới tài nguyên trên cả hai trung tâm trầm tích Beetaloo, bao gồm ít nhất sáu giếng khoan định giới trong 18 tháng tới hợp tác với Daly Waters Energy, INPEX và Santos.

Chương trình đầu tư vốn rộng lớn hơn sẽ phụ thuộc một phần vào việc lựa chọn đối tác chiến lược và thỏa thuận về chương trình làm việc liên quan. Ban quản lý cho biết các cuộc thảo luận đang tiến triển nhưng không cung cấp lịch trình giao dịch.

Rủi ro và các lĩnh vực trọng tâm

• Tamboran có chưa đầy 90 ngày lịch sử khai thác từ bất kỳ giếng nào, làm hạn chế khả năng đánh giá về tỷ lệ suy giảm dài hạn và mức độ thu hồi.
• Cát đỏ Beetaloo đã hoạt động đúng như kỳ vọng trong các thử nghiệm bơm và chất đánh dấu ban đầu, nhưng độ bền của loại cát này dưới sự thay đổi ứng suất vỉa đòi hỏi phải có lịch sử khai thác dài hơn.
• Sản lượng bán ra hiện tại phụ thuộc vào lượng đăng ký mua của Chính quyền Lãnh thổ Bắc Úc và chịu ảnh hưởng bởi sự thay đổi nhu cầu theo mùa cho đến khi giai đoạn cung cấp bao tiêu bắt đầu.
• Việc mở rộng Trạm nén Sturt Plateau phụ thuộc vào niềm tin rằng hạ tầng đường ống của bên thứ ba xung quanh có thể vận chuyển lượng khí đốt tăng thêm đến các thị trường bổ sung.
• Thời điểm và quy mô chi tiêu vốn trong tương lai vẫn gắn liền với các cuộc đàm phán với đối tác chiến lược và sự thống nhất về các ưu tiên phát triển.
• Các hợp đồng mua bán khí đốt ràng buộc tại Bờ Đông dự kiến sẽ yêu cầu xác định rõ ràng hơn về tài nguyên và giảm thiểu thêm rủi ro dưới lòng đất.

Tóm tắt phần Hỏi & Đáp với chuyên gia phân tích

Các chuyên gia phân tích tập trung vào hiệu quả khoan, dữ liệu suy giảm giếng, khả năng mở rộng quy mô sử dụng cát địa phương, chi tiêu vốn và phát triển đường ống.

Ban quản lý cho biết hiệu suất khoan cải thiện là nhờ thiết kế lại mũi khoan, các công cụ chống rung, điều chỉnh kế hoạch định hướng và kiểm soát nhiệt độ giàn khoan tốt hơn. Việc lặp lại quy trình, đội ngũ nhân sự ổn định và hoạt động gia tăng trên toàn bồn địa được xác định là các yêu cầu chính để tiến tới phát triển đá phiến chi phí thấp hơn.

Về khai thác, ban quản lý cho biết hai giếng được ưu tiên đang hoạt động đúng như kỳ vọng và cho dữ liệu áp suất khả quan. Câu hỏi quan trọng còn lại là sản lượng sẽ suy giảm như thế nào theo thời gian. Các giếng bổ sung có thể đóng góp khi lượng đăng ký mua tăng lên, nhưng chỉ có hai giếng dự kiến sẽ được ưu tiên để duy trì lịch sử hiệu suất dài hạn.

Tamboran chưa có kế hoạch sử dụng cát địa phương cho toàn bộ một giếng cho đến khi có đủ bằng chứng khai thác. Công ty sẽ đánh giá liệu các giai đoạn dùng Cát đỏ có duy trì được đóng góp tương đối khi áp suất vỉa giảm hay không. Nếu hiệu suất vẫn tương đương, ban quản lý cho biết cát địa phương cuối cùng có thể chiếm hầu như toàn bộ chất chèn được sử dụng trong bồn địa.

Về hạ tầng Bờ Đông, ban quản lý cho biết APA đang đẩy nhanh thủ tục cấp phép và giải phóng mặt bằng. Tuy nhiên, các cam kết thương mại ràng buộc dự kiến sẽ diễn ra sau khi có thêm dữ liệu khai thác và kết quả thẩm lượng giúp xác định rõ ràng hơn nền tảng tài nguyên.

Toàn văn biên bản cuộc họp báo cáo kết quả kinh doanh

Toàn văn cuộc gọi công bố kết quả kinh doanh

Phần trình bày của ban lãnh đạo

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.

Phần hỏi đáp

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.