Hello everyone, and welcome to Tamboran Resources' Financial Year 2026 First Quarter Earnings Presentation. My name is Dick Stoneburner, and I'm the Chairman and Interim CEO of Tamboran 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 Tamboran as we continue to progress toward initial gas sales from the Beetaloo 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 Tamboran Resources, the Beetaloo 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-Velkerri 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 Tamboran-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 APA-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 delivered and 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 Tamboran and Falcon is a logical consolidation of two of the Beetaloo Basin's most active companies and is expected to strengthen Tamboran's acreage position across the majority of the Beetaloo Depot Center following the checkerboard process with DWE. Following the end of the quarter, Tamboran announced the completion of a public offer to raise $56.1 million before fees at $21 per share and had entered into subscription agreements with certain investors to raise up to $32 million 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 a $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 Tamboran's Beetaloo Basin development. Finally, we ended the quarter with a $39.6 million in cash and expect to receive near-term cash inflows of $100 million following the completion of the public offer, the PIPE transaction, and the acreage sale to Daly Waters Energy, which was announced in May of 2025. Moving to slide four, during the quarter, we announced that Tamboran 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 Beetaloo Basin back in the late 1990s to key stakeholders being the supportive native title 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 title holders, 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. Tamboran and Daly Waters Infrastructure have also secured up to $118 million 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 Darwin. The combination of our current cash balance, receivables, and debt facility puts Tamboran 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 Beetaloo Basin, delivering an average Spud to TD of 26.7 days. Each well was successfully drilled and cemented with a 10,000-foot horizontal section within the mid-Velkerri 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 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 Beetaloo West acreage. We have made some minor modifications to our stimulation design following the incorporation of lessons learned from the SS1H and the SSHT1 wells. The main adjustment is to replicate the proppant and fluid intensity that we used on the SS1H well with target proppant intensity of approximately 220-250 pounds per foot. The stimulation program is expected to be completed by the end of 2025 and commence flow testing in the 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. Tamboran and DWI secured up to $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 an AUD 75 million guarantee on Tamboran's AUD 90 million net share of the project cost. Moving to slide eight, the APA Group-operated Sturt 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 Beetaloo Basin, Falcon Oil and Gas. Falcon holds 22.5% non-operated interests in the acreage in the western Beetaloo with Tamboran and Daly Waters Energy. This acquisition provides Tamboran 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 Tamboran's acreage position within the Phase II Development Area, on which we are currently processing a farm-out process with RBC Capital Markets. On completion of the transaction, Tamboran will have the largest acreage position within the Beetaloo Basin Operations with 2.9 million net acres and an enterprise value of greater than $500 million. The transaction is expected to complete during the first quarter of 2026, following shareholder votes from Falcon Oil and Gas and Tamboran shareholders. Moving to slide ten, further to the RBC Capital Markets farm-out process, we have worked with our partners Daly Waters Energy 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 Daly Waters Energy and 22.5% by Falcon Oil and Gas, and expected to be Tamboran's post-shareholder vote approving the acquisition. Following the completion acquisition of Falcon Oil and Gas and the acreage swap with Daly Waters Energy, Tamboran and Daly Waters Energy will hold 50-50 on the pilot area and 78-22 on the phase II 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 Helmerich & Payne and Liberty Energy as a strategic partner with Tamboran. 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. Tamboran and Baker have entered into a preferred services agreement where Baker will supply oilfield services and support optimization and efficiency initiatives in Tamboran'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 in cash on the balance sheet, with near-term cash inflows of $100 million, including $53 million post-fees that we have received from the recently announced public offer, $15 million from the acreage sale to Daly Waters Energy, which was announced in May, and $32 million of subscription agreements from certain investors under the PIPE transaction. We are also working on securing a research and development rebate for fiscal year 2024, 2025, and 2026 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 IP 30 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 Tamboran 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. At this time, we'll conduct our question-and-answer session. If you would like to ask a question, please press star one 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 two 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. Your first question comes from Scott Hanold with RBC Capital Markets. Please state your question. Yeah, thanks. Thanks, Dick, for all that detail. My first question, it might be for Eric. And look, you all shorted up your funding pretty well here over the last few months. If I'm just focused on just the pilot project right now, can you talk status quo? How does the capital spend look over the next few quarters into first production? What do you expect kind of that quarterly progression to look like? Remind me with the Falcon acquisition, is that going to be a net cash inflow for you guys net of fees? Yeah. Hey, Scott. That's great. Look, we had $39.6 million in cash on the balance sheet at the end of the quarter. In the public offer, we raised $56 million in additional. That brings us to a total of $95.6 million. We also have the PIPE for $32 million that shareholders will vote on in a few weeks. That'll 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've raised up to $30 million in that. That puts us closer to that $160 million mark. There is some additional R&D that Dick just spoke about. That is a really great scheme in Australia. Remember, a lot of what we're doing is the first time that this oilfield services and technology and completion strategies have been employed in Australia. It does qualify for R&D. I think the point is we're well funded. The spending is, as we've guidelined and highlighted before, as we're going through this, there remains to be about AUD 95 million, so call it $70 million or $62 million, and that's Tamboran that remains to be spent. Then there's another AUD 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. Everything's consistent with previous guidance, and now we're even better funded than before. 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. Kind of coming back to where we got to on this funding, we're well funded for everything. 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. 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. Dick, this one might be for you. Just talk about the stimulation process of this next well first. A little bit, could you give us a little bit of context around that 4H well first and just it sounds like there was a coil tubing issue there. Was it maybe more mechanical, which obviously had you move to the sixth? If you could give some commentary around that. With you specific to the sixth well, it sounds like you guys pressure tested. You started sort of some of the stimulation operations. Is there any detail from that pressure test and the initial kind of work you've done that you can provide us? Yeah. On the first thing, Scott, good to hear from you. Remind me of the first part of the question. Yeah. 4H. 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. 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. It's unfortunate. It's a very clean break. We saw that when we pulled out. It's a very fishable situation. We believe that the coil will be sticking up, which makes the fishing progress even less risky. 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. What we reported was what we knew at the time and putting together. I can't really give you any details on what's happened since we filed this, but everything's going fine. No hiccups, no nothing. We're just proceeding ahead. 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. We're well at the hold, and things are going quite well. Appreciate that. Just clarifying that the coil tubing thing on the 4H well, 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 based crew, or is it more of a local crew that just needs more reps at it? It's the latter. We've experienced this type of thing before. This type of operation is not something that the oilfield workforce in Australia is used to. Running multiple frac stages where you're running four or five frac stages a day becomes quite repetitive. Until you get that rhythm and you really have that type of repetition, you're running risk of relatively inexperienced oilfield service hands. At least this is the way I view it. 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. 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. 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. From an overall risk perspective of what we have in front of us, I think it's very, very low risk. Appreciate that. Thank you. Thank you. Your next question comes from Calay Akamine with Bank of America. Please state your question. Hey, good afternoon, team. Eric, Dick. I want to start on the completion design. On the last call, Dick, I think you suggested that less proppant could result in a better well. It sounds like proppant intensity on 6H here has been dialed back a bit versus 2H. I know some of this is trial and error, but I imagine that there is a geological thesis behind it. Hoping that you can share a little bit about your chosen well design. We have got two data points, right? First data point, 2,250 pounds per foot. It is around 55 barrels per foot. Really right in the wheelhouse of most of your slightly overpressured or normally pressured shale plays. Now, you look at, let us call it a Haynesville 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 proppant and water. The two designs we have 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. Those both kind of bracket around most designs in U.S. shale plays. I do not see that we know the answer yet. 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 well. We can also spend a little less money. If we feel like this reservoir can perform optimally with a little less water and a little less sand, and we save a little bit of money, that is kind of bracketing the decision, Calay. We will find out when we continue to get more experience and more reps and understand more about the reservoir. Right now, it is 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. My second question. My second question. From a rock standpoint. Yeah, I'm sorry. I think you did quiz as to whether there's anything about the rock, porosity, permeability, anything that we're reacting to there. I'd say no. We're really reacting to well performance in the two designs that we've come so far. We think that these wells are kind of right next to each other. 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. It's really just kind of landing on what seems to have worked 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 your contract is to flow 40 million cubic feet per day starting, call it mid-year 2026. I would imagine that Darwin would like to take as much gas as possible. Do you see any upside opportunities to gas shales 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 is probably a relatively conservative number that this system can deliver. We think that it is possible that this system can deliver up to 50 million a day. Let us just say 40-50 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 are probably looking at maybe, what, 12-18 months from today where we could actually increase that compression, probably for a third the cost of what we spent on the initial phase I. We will immediately begin working toward increasing from 40 to 50 million a day to 100 million a day. Now, that's going to be kind of the limit of this particular system. As you know, the next step would be getting into a long haul pipe. Good stuff. I appreciate that. Thank you. Thank you. Your next question comes from Charles Mead with Johnson Rice. Please state your question. Yeah. It's a good day to you, Dick and Eric and any other Tamboran people there. Hey, Charles. Good to hear from you. Yeah. Thank you. 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. I wanted to ask about the farm out process again. I know you addressed it last time around. Of course, you don't want to guess on where it's going to be. You sound like you're still confident it's going to conclude in 1Q 2026. 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. Charles, you know better than that. You got to try. 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 as we enter into this process, 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 had the quality of the attendees and the number. It's not too actual what we might expect it, but I think it's a big number. Not only is it a big number, it covers a wide gamut of interested parties. We know that the inventory is. Dick, that's actually good. Go ahead. Yeah. I was just going to say that's actually great detail. We didn't have to do numbers. That's really helpful. I didn't mean to cut you off. Please. 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 II Development Area to 500, that seems not a surprise to me, but that seems kind of like a big deal to me. I know you gave 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 what you get the feedback you're getting from the data room, or was that more driven through conversations with Daly Waters? Just how did that came about? I let the guys chime in because we probably all have a little bit different view on it, but I think it's bigger is better. Most of the participants seem to suggest that if we could add additional acreage as we went through the process, it would be better. We worked with Daly Waters and constructed a situation where we, 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. It's kind of a simple math problem once you see what they brought, what we brought. We each had some number of working interest points within each block. Again, you just kind of do the math, and you come out with a number that ends up with common ownership across 500,000 acres. 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. 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. $500,000 was also prior to the announcement of Falcon acquisition. Look, Falcon shareholders pro forma are following the shareholder vote in early Q1 will become Tamboran shareholders. They'll be holders of Tamboran stock. Adding that acreage, which was not previously contemplated in the farm, just made natural sense. I do agree with Dick. Bigger is better. In Australia, I mean, net to us, we got 2.9 million acres pro forma of Falcon's acquisition. It only made sense to ratchet up and make sure that they are included as part of that, as part of our new shareholder base. That makes sense. Thank you, Dick. Thank you, Eric. Thank you. Just a reminder to the audience to ask a question, press star one on your phone now. To remove your question from the queue, you can press star two. 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. Good to be here. Good Good to be here. Good to hear. On the line. Yeah. 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 EURs, IPs, decline rates, or kind of any just kind of framing around your expectations there? Let me just kind of start with how we intend on flowing it back. I mean, I think I've already addressed how the design is varying between the first two wells and landed on the 2,250 pounds per foot. We will finish the job over the course of the next three weeks or so. Then we will rig down. We will do similar type flowback to what we have been doing before with what I would call a qualitative statement that we will not flow it as hard. I am a strong believer, particularly in overpressured reservoirs. The pressure management at the surface is incredibly important. It is something that I learned early. Our team learned early in the Hamesville, and it proved to be very, very beneficial to well performance to maintain that drawdown, limited drawdown on the reservoir. We do want to get the water off. We'll probably flow it for, generally speaking, about a week to 10 days and get it down to about 150 barrels per million. Then we'll shut it in. 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 that 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. As you're soaking it, that allows a much more direct path, if you will, of that imbibed gas into the wellbore and relatively low water rates to begin with. 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. What we're doing, and like any new play, we're going to test different models. For this particular well, we're probably going to shut in between 21 days and maybe 30 days as midpoints for—excuse me, we had an intrusion here. We haven't decided for sure, but probably somewhere between 20-30 days as a soak period for the period before we actually start our flow test. 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. We'll probably land on our 30-day test, but that's not written in stone either. Hopefully, that answered 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. There was some, I think, staging and 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. What we plan on doing is pump probably two to three stages in the heel of the well. We are going to pump those in various quantities of native sand and regular sand, if you will. We are going to tag stages on either side of those and then tag with tracer. We'll have the local sand tagged with tracer, and we'll have the full, I'll call it again, regular sand stages on either side of the local sand. We'll have a comparative analysis between stages on either side and then the stages that we pump with the local sand or the, yeah, the local sand. Those will be in different proportions. 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 tracer. That'll 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. I'll leave it there. Thank you. Good. Thank you. Your next question comes from Anish Kapadia with Hannam & Partners. Please state your question. Hi. It's Anish Kapadia here from Hannam. Just a couple of questions, please. Firstly, just going back to the farm out, I was just more interested in terms of some of the types of companies that you're looking at. 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? 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. Again, somewhat like my flipping 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. All companies do. All companies have strengths. 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 farmie. We may stay 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. 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 basin is getting a lot of attention, not only from the market itself, but from operators and companies around the globe, for that matter. I am 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. Then some bring various levels of midstream marketing across the globe as well. We are just really happy about what those people bring, all of them. We will figure out what the best partner is for us. Hopefully, that'll be within the next 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 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 Aripura Rare Earths Critical Minerals Project that just hit FID directly south of us in the Northern Territory. The robust demand locally is pretty impressive. Your question was on LNG, and we've seen JKM hovering around a low, call it $11 per MMBTU. Look, in that market, I think you can look at our cost structure and where we're going to get it to. You've seen some additional disclosure with us in our presentation that we're going to make really good returns in there. I think first and foremost, what we have to do is you got to provide gas to the local 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 kind of energy shortfalls. It does. Tamboran 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.