Tamboran Resources Corporation

Hello, everyone, and welcome to Tamborin Resources' financial year 2026 first quarter earnings presentation. My name is Dick Stoneburner, and I'm the chairman and interim CEO of Tamborin Resources, and I'm joined here today with our chief financial officer, Eric Dyer. Moving to slide two, you can see our disclaimer, which relates to forward-looking statements within the presentation. I encourage you to review this at your leisure. Moving to slide three. The first quarter of FY26 has been a transformational period for Tamborin as we continue to progress toward initial gas sales from the Beataloo Basin. During the quarter, we made the historic decision to sanction the Shenandoah South pilot project following execution of key commercial and stakeholder approvals. The decision to sanction the pilot project is a major milestone in the history of Tamborin resources the Beedloo Basin, and the Northern Territory. In October, we successfully completed the first batch drilling campaign in the basin, with three wells drilled and cemented with full 10,000-foot horizontal sections within the mid-Valkyrie B Shale. We commenced the Stimulation Program on the SS6H well earlier this week, and the program is planned to be completed before the end of the year. The remaining two wells from this drilling program and the SS3H, drilled and uncompleted well, are planned to be stimulated in the first half of 2026. Construction activities were commenced on the Tamborne-operated Sturt Plateau Compression Facility, also known as the SPCF. At the end of October, the project was 68% complete, and importantly, tracking the P50 budget and schedule. The project remains on track to deliver first gas in mid-2026. The AP-operated Sturt Plateau pipeline also commenced construction during the quarter and is currently within budget and on schedule. In September, we announced that we had entered into definitive agreements with Falcon Oil and Gas to acquire the subsidiaries of the company in a cash and script deal. The transaction between Tamborin and Falcon is a logical consolidation of two of the VLU Basin's most active companies and is expected to strengthen Tamborin's acreage position across the majority of the VLU depot center following the checkerboard process with DWE. Following the end of the quarter, Tamborin announced the completion of a public offer to raise 56.1 million U.S. before fees at U.S. $21 per share. and had entered into subscription agreements with certain investors to raise up to 32 million U.S. via a pipe transaction. The pipe transaction is subject to a shareholder vote, which is scheduled for January 2026. The public offer was supported by U.S. $10 million investment from leading energy technology company, Baker Hughes. Baker will provide industry-leading oilfield services and equipment while supporting optimization and efficiency initiatives for Tambourine's Beedaloo Basin development. Finally, we ended the quarter with a US $39.6 million in cash and expect to receive near-term cash inflows of $100 million US following the completion of the public offer, the pipe transaction, and the acreage sale to DWE, which was announced in May of 2025. Moving to slide four. During the quarter, we announced that Tamborne and our JV partners had officially sanctioned our Shenandoah South pilot project, targeting delivery of gas to the Northern Territory government from mid-2026. I would like to thank all of those who have made this possible, from a history of explorers who recognized the Beedaloo Basin back in the late 1990s, to key stakeholders being the supportive Native tidal holders, the Northern Land Council, and the Northern Territory Government. We would also like to thank our many shareholders for their dedicated support in bringing this project to life. The decision to take FID follows the execution of key commercial documents with the APA Group and the SPCF Trust and follows the signing of agreements with native titleholders with the support of the Northern Land Council and the Northern Territory Government stepping up to secure approvals required to commence sales of appraisal gas under the beneficial use of gas legislation. Tambourine and Daly Waters infrastructure have also secured up to $118 million U.S. via a financing facility with a consortium of lenders for the construction of the SPCF, the key infrastructure that will process gas before it reaches the local market in Darwins. The combination of our current cash balance, receivables, and debt facility puts Tamborne in a position to fund its share of the upstream drilling and stimulation of the remaining pilot project wells required to reach plateau production and construction of the SPCF. Both the construction of the SPCF and SPP are on time and on budget. We remain on track to deliver first gas sales via commissioning in mid-2026, subject to weather and successful completion of stimulation activities. Moving to slide five, in October, we successfully completed the first batch drilling program in the Beedaloo Basin, delivering an average FUD to TD of 26.7 days. Each well was successfully drilled and cemented with a 10,000-foot horizontal section within the mid-Belcary B Shale. The drilling program was completed ahead of schedule and below budget, supported by the application of new technologies to deliver increased efficiencies. Combining the best section of each of these three wells would have delivered spud to TD duration of less than 20 days, which is where I believe these wells will get to in the very near future. While we successfully completed the drilling campaign, In preparation for the stimulation of the SS4 well, we had an issue with our coil tubing. And rather than try and resolve it and risk delay with Liberty Energy, who was mobilizing the frac fleet to site, we have decided to stimulate the SS6H well instead to remain on schedule and on time. Moving to slide six. As I mentioned earlier, we have commenced the stimulation of the SS6H 6H well following the successful pressure testing earlier this month. Liberty Energy were efficient in mobilizing their equipment and preparing for the 60-stage program in the deepest region of the BDLU West Acreage. We have made some minor modification to our stimulation design following the incorporation of lessons learned from the SS1H and the SHST1 wells. The main adjustment is to replicate the profit and fluid intensity that we used on the SS1H well with target profit intensity of approximately 2,250 pounds per foot. The stimulation program is expected to be completed by the end of 2025 and commence flow testing in first quarter of 2026, subject to weather conditions and soaking duration. Moving to slide seven. Construction activities on the SPCF commenced following the approvals from the Northern Territory Government. The compressor and TEG units were delivered to site and activities to install units are underway. At the end of October, the project was 68% complete and within the P50 budget and schedule, which remains on track for mid-2026, subject to weather conditions. Tamborne and DWI secured up to U.S. $118 million in funding for the remaining costs of the SPCF facility with a consortium of lenders to cover the P90 cost estimate. The debt facility is supported by the Northern Territory Government via a $75 million Australian guarantee on Tamborne's $90 million Australian net share of the project costs. Moving to slide eight. The AP-operated Stewart Plateau pipeline commenced work during the quarter, with 60% of the pipeline now welded. As you can see in the photos, the pipeline construction is going well and is currently within budget and schedule. The project is expected to reach practical completion by the end of the year. Moving to slide nine. During the quarter, we announced the acquisition of our joint venture partner in the Beedaloo Basin, Falcon Oil and Gas. DAPN holds 22.5 non-operated interest in the acreage in the western Beteloo with Tamborin and Daily Waters Energy. This acquisition provides Tamborin with acreage covering the entire EP 76, 98, and 117 permits following the checkerboard process we announced with DWE in May 2025. Importantly, the transaction increases Tamborin's acreage position within the Phase II development area. on which we are currently progressing a farm-out process with RBC Capital Markets. On completion of the transaction, Tamborin will have the largest acreage position within the BDLU Deficit Center with 2.9 million net acres and an enterprise value of greater than $500 million U.S. The transaction is expected to complete during the first quarter of 2026. following shareholder votes from Falcon and Tamborne shareholders. Moving to slide 10, further to the RBC farm-out process, we have worked with our partners DWE to increase the acreage consideration to 500,000 acres in the Phase II development area. This plan adds approximately 100,000 acres from an area south of the original acreage position which was owned 77.5% by DWE and 22.5% by Falcon, and expected to be the Tamborne's post-shareholder vote approving the acquisition. Following the completion acquisition of Falcon and the acreage swap with DWE, Tamborne and DWE will hold 50-50 on the pilot area and 78-22 on the phase two development area. This will increase our interest in retention license 10 to 92%. Moving to slide 11, as we announced in conjunction with our public offer, leading energy technology company, Baker Hughes, joined Helmer & Payne and Liberty Energy as a strategic partner with Tim Warren. Baker supported our recent public offer with a $10 million U.S. equity investment. and we are working closely with the company to support the development of our Beetaloo Basin acreage. Tamborne and Baker have entered into a preferred services agreement where Baker will supply oilfield services and support optimization and efficiency initiatives in Tamborne's initial development. Baker Hughes has been working with us across the initial and recent Shenandoah programs. They continue to lead the new oilfield services technologies and practices that have not been utilized before in Australia. We are very thankful for their support, and this partnership establishes a framework for us to reduce costs, collaborate, and increase efficiencies across our activities. Moving to slide 12, you can see that following our recent capital raise, we are well positioned to fund our pilot project to initial gas sales in mid-2026. At the end of the quarter, we had approximately $40 million U.S. in cash on the balance sheet, with near-term cash inflows of 100 million U.S., including 53 million U.S. post fees that we have received from the recently announced public offer, $15 million U.S. from the acreage sale to DWE, which was announced in May, and 32 million U.S. of subscription agreements from certain investors under the PIPE transaction. We are also working on securing a research and development rebate for fiscal year 24, 25, and 26 that could, if approved, provide incremental cash inflows. Moving to slide 13, we have a very busy year ahead of us as we progress towards initial gas sales in mid-2026. As discussed earlier, we have commenced the 60-stage stimulation program of the SS6H well, which is expected to be completed by the end of the year. The well is expected to commence IP30 flow testing during the first quarter of 2026, subject to the duration of soaking. Following the completion of the wet season, we plan to stimulate the remaining three wells to achieve initial gas sales of 40 terajoules per day for mid-2026. We expect to finalize the farm out of the Phase II development area in Q1 2026 and drill several carried wells during the remainder of the calendar year. These wells will be a step towards delineating a large gas resource required to underpin a new pipeline to the East Coast market. We also expect to complete the Falcon transaction during the first quarter of 2026, which requires a shareholder vote from Tamborin and Falcon shareholders. I want to thank all of our shareholders for the continued support and look forward to providing an update on our activities at our next earnings call in February of 2026. With that, I'd like to hand over to the operator for questions.

Thank you. And at this time, we'll conduct our question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. A confirmation tone will indicate that your line is in a question queue. You may press the star key followed by the number 2 if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we pull for questions. And your first question comes from Scott Hanold with RBC Capital Markets. Please state your question.

Yeah, thanks. Thanks, Dick, for all that detail. You know, my first question, it might be for Eric, and look, you all shored up your funding pretty well over the last, you know, few months, and if I'm just focused on, you can focus on just the pilot project right now, can you talk status quo, like how the capital spend looks over the next few quarters into first production, what you expect kind of that quarterly progression to look like, and remind me with

um the felican acquisition are you is that going to be a net cash inflow for you guys net of fees yeah hey scott that's great so look we had 39.6 million in cash on the balance sheet uh at the end of the quarter on the public offer we raised 56 million in additional that brings us to a total of 95.6 We also have the pipe for $32 million that shareholders will vote on in a few weeks. That will bring us to a total of $127.6 million. Concurrently, we're running what is a share purchase plan for our ASX-listed shareholders. We can raise up to $30 million in that, so that puts us closer to that $160 million mark. And then there's some additional R&D that Dick just spoke about. That is a really great scheme in Australia that, you know, remember a lot of what we're doing is the first time that the soil field services and technology and completion strategies have been employed in Australia, so it does qualify for R&D. So I think the point is we're well-funded. The spending is, as we've guideline and highlighted before, you know, as we're going through this, There remains to be about 95 million Australians, so call that 70 million U.S. or 62 million U.S. net to Tamborne that remains to be spent. And then, you know, there's another 33 million required on the SPCF. Remember the SPCF, we've secured the debt facility. We're still tracking that on time, on budget. APA is doing the interconnect that we're not spending money on. That's the SPP that is also on time, on budget, tracking at the P50. So everything's consistent with previous guidance, and now we're even better funded than before. And then as far as Falcon, there is some additional spending with Falcon, picking up their share of the work programs. It costs an additional $10 million. There's the $23 million in cash that was part of the transaction, and then an incremental $11 million in other costs related to the transaction. So kind of coming back to where we got to on this funding, we're well-funded for everything. Yeah, we don't need to come back to the market for quite some time. Really on track, on budget, everything that we've highlighted earlier we're going to be able to deliver. And you can even see us expedite a few things and do some pretty interesting things with some of the funds that we raised in this round to help expedite the business plan.

Thanks. I appreciate that. And, you know, Dick, this one might be for you. Just, you know, talk about the stimulation process of this next well first. You know, a little bit, you know, could you give us a little bit of context around that 4H well first and just, you know, it sounds like there was a coil tubing issue there. You know, was it maybe more mechanical and, you know, which obviously, you know, had you moved to the 6th, but... You know, if you could give some commentary on that. And then with you, specific to the sixth swell, you know, it sounds like you guys pressure tested. You started sort of some of the stimulation operations. Is there any detail, like, from that pressure test and the initial, you know, kind of work you've done that you can provide us?

Yeah, on the first, hey, Scott, good to hear from you. On the, remind me of the first part of the question. Yeah, 4-H, you know, it was an unfortunate circumstance that was not related to any accident on our part. Unfortunately, a service company kind of made a mistake in rigging up the coil through the BHP, and we inadvertently sheared the coil because of that. All costs are going to be picked up by that service company, so it's not going to cost us anything, and it also is not going to set us back. because basically we just moved immediately over to the 6H well and commenced stimulation activity on it. So it's unfortunate. It's also a very clean break. We saw that when we pulled out. So it's a very fishable situation. We believe that the coil will be sticking up, which makes the fishing progress even less risky. So, you know, we'll get that done as soon as we finish the operation on the 6H and get that ready for our campaign in the spring. Secondarily, the progress, it's going fine. You know, what we reported was what we knew at the time and putting together, and I can't really give you any details on what's happened since we, you know, filed this, but everything's going fine. You know, no hiccups, no nothing. We're just proceeding ahead. You know, I'll just tell you that you've probably heard and seen this. All the co-stages and the first couple of stages are a little more challenging just because you haven't established conductivity. But, you know, we're well at the hold, and things are going quite well.

Appreciate that. And just to clarify on that, the coil tubing thing on – the 4H-12, would you, you know, what analogy would you give us? Do you think some of that is just from the service company perspective? Is it just the crew needs to sort of learn the process a little bit more? Is it a U.S. sort of base crew, or is it more of a local crew that just needs more reps at it?

It's the latter. You know, we've experienced this type of thing before, and, you know, we just, this type of operation is not something that the, The oil field workforce in Australia is used to, you know, running multiple practice stages where you're running four or five practice stages a day. It becomes quite repetitive. But until you get that, you know, get that rhythm and you really have that type of repetition, you're running risk of relatively inexperienced oil field service hands, at least this is the way I view it. Now, I wasn't on location. I'm not an engineer, but I do feel confident in saying that, It's inexperience. It's rigging something up that I think in the United States people do in their sleep. But over there, it's just not the same experience level to perform at the high levels that we see over here. Time will fix that. And fortunately, at least knock on wood, it doesn't look like it's anything that will set us back. Anytime the word fishing is in a sentence, I get nervous. But from an overall perspective, you know, risk perspective of what we have in front of us, I think it's very, very low risk. Appreciate that. Thank you.

Thank you. And your next question comes from Kalei Ackermine with Bank of America. Please say your question.

Hey, good afternoon, team. Eric, Dick. I want to start on the completion design. So in the last call, Dick, I think you suggested that less cropping could result in a better wealth. It sounds like profit intensity on 6H here has been dialed back a bit versus 2H. And I know some of this is trial and error, but I imagine that there is a geological thesis behind it. So hoping that you can share a little bit about your chosen well design.

Well, you know, we've got two data points, right? First data point is 2,250 pounds per foot. It's around 55 barrels per foot. really right in the wheelhouse of most of your slightly overpressured or normally pressured shell plays. Now, you look at, let's call it a Hainesville well, where people are pumping 3,500 and 4,000 and maybe even 5,000 pounds per foot. That design is obviously considerably different, both in profit and water. But the two designs we've done so far, the one I just referenced at 2,250 and the second one that we did at 2,800 pounds, which by definition elevated the water up to about 70 barrels per foot. You know, those both are kind of bracket around most designs in U.S. shale plays. So, you know, I don't see, you know, that we know the answer yet. But the one thing we do know is that the performance, at least on a prorated extrapolated rate for the one well is a little bit better than the two wells. and we can also spend a little less money. So if we feel like that this reservoir can perform optimally with a little less water and a little less sand, and we save a little bit of money, that's kind of bracketing the decision. We'll find out when we continue to get more experience and more reps and understand more about the reservoir. But right now, it's really just kind of looking at the two wells, seeing the results, and kind of landing on something closer to the first well than the second well.

I appreciate that, Dick.

There's nothing from a rock standpoint. I'm sorry. I think you did a quiz as to whether there's anything about the rock, you know, porosity permeability, anything that we're reacting to there, and I'd say no. We're really reacting to well performance in the two designs that we've pumped so far. We think that, you know, these – These wells are kind of right next to each other. So I think we're going to stipulate to the fact that the rocks are consistent across the area that we're testing and very, very good. So it's really just kind of landing on what seems to work best so far.

That's very thorough. I appreciate that answer, Dick. For my second question, I want to ask about the pilot project. So you're contracted to flow 40 million cubic feet per day starting, call it mid-year 2026. I would imagine that Darum would like to take as much gas as possible. Do you see any upside opportunities to gas sales in the northern territory?

Absolutely, for sure. Number one, we keep using 40 million a day or 40 terajoules a day, which is basically the same answer. That's probably a relatively conservative number that this system can deliver. We think that it's possible that this system can deliver up to 50 million a day. But let's just say $40 to $50 million once we have it completed and fully commissioned. We plan to immediately, not just to immediately, we are currently working toward an expansion of that project. We need certain elements to that facility to plan ahead to be able to implement it. We're probably looking at maybe, what, 12 to 18 months from today where we could actually increase that compression probably for a third the cost of what we spent on the initial phase one. So we will immediately begin working toward increasing from $40 million to $50 million a day to $100 million a day. Now, that's going to be kind of the limit of this particular system. So, as you know, the next step would be getting into a long-haul pipe.

Good stuff. I appreciate that. Thank you.

Thank you. And your next question comes from Charles Mead with Johnson and Rice. Please state your question.

Yes, good day to you, Dick and Eric, and any other Tim Bourne people there. Dick, Charles, good to hear from you. Yeah, thank you. You know, Dick, I know we had a call like this a month, month and a half ago when you guys reported last quarter because of the fiscal year end, but I wanted to ask about the farm-out process again. I know you addressed it last time around, and of course you don't want to guess on where it's going to be, but you sound like you're still confident it's going to conclude in 1Q26, and I'm just wondering if you could give us any update, perhaps along the lines of how many total CAs or how many data room presentations you guys, management presentations you guys went through, and if there have been any late additions to the process. Oh, you know better than that.

Well, you've got to try. And sometimes I'm a sucker for giving stuff that I shouldn't say, but I think I know I need to keep pretty quiet on that. I'll kind of say what you probably already know. It's a robust process. I would say that, you know, as we enter into this process, if we – to predict that we got as much interest in it as we do, I would say – I'm surprised. I would not have predicted that we would have the quality of the attendees and the number. And it's not too much of what we might expect. But I think it's a big number. And not only is it a big number, it covers a wide gamut of interested parties. And you know that the inventory is great.

Yeah, I was just going to, that's actually great detail. That's, you know, if it doesn't have any numbers, that's really helpful. I didn't mean to cut you off. Did I already say too much? No. Look, my second question, which is kind of perhaps, which is kind of dovetails with this a bit, the increase of the phase two development area to 500, that seems, you know, not a surprise, but that seems kind of like a big deal to me. Can you I know you give us some of the rationale, but can you give a little bit of the narrative of what the driver for that was? Was that a driver from the feedback you're getting from the data room, or was that more driven through conversations with Daily Waters? Just how that came about.

You know, I let the guys chime in because, you know, we probably all have a little bit different view on it, but I think it's bigger is better. Most of the participants seemed to suggest that if we could add additional acreage as we went through the process, it would be better. So we worked with Daily Waters and constructed a situation where we, you know, okay, you own this, we own that. Let's unitize across that area and come up with a number that we can deliver to the participants. And it's kind of a simple math problem once you see you know, what they brought, what we brought. We each had, you know, some number of working interest points within each block. But again, you just kind of do the math and you come out with a number that, you know, ends up with, you know, common ownership across 500,000 acres. And it's geologically similar. I think that's what we wanted to do. We wanted to make sure that the blocks were all very attractive geologically. that we didn't degrade the overall attractiveness from a reservoir quality and pressure situation that we see under that 500,000 acres. So we wanted to tailor it to what the participants seem to be indicating and keep it high quality.

Yeah, I think further, Charles. Go ahead, please. 100,000 was also prior to the announcement of the falcon acquisition, and, you know, look, Falcon shareholders pro forma, they are following a shareholder vote in early Q1, will become Tamborin shareholders. They'll be holders of Tamborin stock. And adding that acreage, which wasn't previously contemplated in pharma, just made natural sense. And, you know, I do agree that bigger is better. In Australia, I mean, net to us, we've got two point in pro forma of Falcon's acquisition, we've got 2.9 million acres. it only makes sense to ratchet up and make sure that they're included as part of that, as part of our new shareholder base.

That makes sense. Thank you, Dick. Thank you, Eric.

Thank you. And just a reminder to the audience, to ask a question, press star 1 on your phone now. And to remove your question from the queue, you can press star 2. And your next question comes from Paul Diamond with Citibank. Please state your question.

Thank you. Good afternoon, all. Thanks for taking the call. Just wanted to touch base. Thank you. Can you touch base on SS6H? You talked about expectations around lessons learned and best practices. Can you talk about how you potentially see that impacting whether the URs, IPs, decline rates, or kind of any kind of framing around your expectations there?

Well, Let me just kind of start with how we intend on flowing it back. I think I've already addressed how the design is varying between the first two wells and landed on, you know, the 2,250 pounds per foot. So we'll finish the job over the course of the next three weeks or so. Then, you know, we'll rig down and we'll do similar type flow back to what we've been doing before with what I'd call a qualitative statement that we won't flow it as hard. I'm a strong believer, particularly in over-pressured reservoirs, that pressure management at the surface is incredibly important. It's something that I learned early, our team learned early in the Haynesville, and it proved to be very, very beneficial to well performance to maintain that drawdown, limited drawdown on the reservoir. So we do want to get the water off, and so we'll probably flow it for, generally speaking, about a week to 10 days, and get it down to about 150 barrels per million. and then we'll shut it in. And this is where we're still learning. We know this is a very old, very desiccated reservoir. You know that we've soaked our previous two wells, one of them 21 days, one of them 60 days. The team has a very robust model that they worked with CoreLab on developing. It predicts the type of performance we get from a soak where we actually get imbibition of the water and gas. In other words, the gas takes the water's place, or the water takes the gas's place in the reservoir. And as you're soaking it, that allows a much more direct path, if you will, of that imbibe gas into the wellbore and relatively low water rates to begin with. But once we got into the test, we realized we saw the water rates come back up. The water's not going away completely because we pump a lot of water. So what we're doing, and like any new play, we're going to test different models. And so for this particular well, we're probably going to shut in between the 21 days and maybe 30 days as midpoints. Excuse me, we had an intrusion here. And so we haven't decided for sure, but probably somewhere between 20 and 30 days as a soak period. for the period before we actually start our flow test. And then we'll flow test probably 30 days. We haven't, again, landed on an exact flow test. We've tested up to 90 days, as you know. And so, you know, we'll probably land on our 38th test, but that's not written in stone either. Hopefully that answers your question.

Yeah, got it. I appreciate the detail. Just one quick follow-up. I know you guys have talked about a local sand solution, and it's kind of in process, and there was some, I think, staging inquiry into whether you could find or locate mines relatively close. Any progress there? Any movement at all?

Yeah. Good question. Thank you. I'm glad you asked that because I think it's important for the market to understand. We are progressing in basin sand. We have tested both from a compressive strength and from a size and angularity and other elements that you test regarding the sand itself. Everything lines out to be something that we should be able to pump and we can mine quite readily. And so what we plan on doing is pump probably two to three stages in the heel of the well And we're going to pump those in various quantities of native sand and regular sand, if you will. And then we're going to tag stages on either side of those and then tag with tracer. And so we'll have the local sand tagged with tracer, and we'll have the full, call it again, regular sand stages on either side of the local sand. So we'll have a comparative analysis between stages on either side, and then the stages that we pump with the local sand, and those will be in different proportions. So we're going to kind of cover the whole gamut between all regular sand, all local sand in some combination thereof, and have tracers to verify and tell us how each of those stages perform. Now, if they all perform The ideal situation is they all perform relatively the same based on the trace. That will 100% confirm that the local sand is performing equally as good as the regular sand. Does that answer your question?

It does. I appreciate the clarity. Thank you. Thank you.

And your next question comes from Vanish K. with Hanom. Please state your question.

Hi, it's Anish Kapadi here from Hanom. Just a couple of questions, please. Firstly, just going back to the farmhouse, I was just more interested in terms of some of the types of companies that you're looking at and how important is it the technology that some of these companies are going to bring, or kind of, I suppose, proven track record in shale development, or is it purely the best price you're going to get to kind of farm out the assets? And then the second one was on just a bit of an update, if you can, anything in terms of the gas market in Australia, kind of any impacts of kind of potential lower LNG pricing that might be coming through. Just wanted to see how you're seeing that overall. Thanks.

Yeah, I'll take the first part and let Eric talk about the second. And again, somewhat like my flippant answer to Charles, I don't want to be too specific about the nature of the participants other than they all clearly understand shale exploration production. They all understand shale midstream and marketing. Some understand certain elements of that better than others, as all companies do. All companies have strengths. But I would tell you that the strengths that all of these participants bring dovetail well with ours, in my opinion. I think we will be a very competent operator for some period of time with this participant, with this Farm E, we may stay in the operator forever, or we may have a participant that wants to take over at some point in time down the road. We have a wide range of outcomes in terms of what transpires over the course of the next three or four or five years, but I will tell you all of these participants are very excited about the basin. I think you would probably, being in the market, know that this base is getting a lot of attention, not only from the market itself, but from operators and companies around the globe, for that matter. So I'm just really excited about what everybody brings. Some bring, again, not to repeat myself too much, but some bring great operational experience in North America. Some bring great operational experience worldwide. And then some bring various levels of midstream marketing across the globe as well. So we're just really happy about what those people bring, all of them. And we'll figure out, you know, what the best partner is for us. And hopefully that will be within the next, you know, four or five months.

Yeah. Hey, Anish. Look, I think really good questions and kind of further what Dick was talking about. I mean, look, we have – We have three markets. We have our local NT market, which we now have eyes on since the FID to potentially expand that facility. We're putting pilings and concrete slab in place to be able to expand that very cost-effectively in the future up to potentially that $100 million a day. East Coast market in Australia, which is where we need to get to, is really quite interesting. What you're seeing is you're seeing Recently, there's been announcements of an aluminum smelter, and then on the East Coast, and steelworks in South Australia need gas. They need gas desperately. Remember, we still have a domestic shortfall, and a shortfall is approaching a BCF a day in the next two to three years. We even had an FID. We have an announcement about an MOU, a gas sales agreement with Arapura, where it's a critical minerals project that just hit FID. directly south of us in the Northern Territory. So the robust demand locally is pretty impressive. Your question was on LNG, and we've seen JKM hovering around the low, call it $11 per mm BTU. In that market, I think you can look at our cost structure and where we're going to get it to, and you've seen some additional disclosure with us in our presentation, that we're going to make really good returns in there. But I think first and foremost, what we have to do is we've got to provide gas to the local You know, before you do LNG, you're going to provide gas to the local market and to the Australian East Coast. It's a little crazy to think that you can export when your local market has a kind of energy shortfall. It doesn't. Tamborin is working really hard to solve that problem and be a good member of the community and make sure that we can take care of it and provide the energy that Australia needs to run.

Great. Thanks very much.

Thank you. And ladies and gentlemen, that's all the questions we have for today. So with that, we will conclude today's call. All parties may now disconnect. Thank you for your participation.