Greetings and welcome to the Tamboran Resources Fiscal Year 2025 Fourth Quarter Earnings Release. At this time, all participants are in a listen-only mode. A question and answer session will follow the phone presentation. If anyone should require operating assistance, please press *0 on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Dick Stoneburner. Thank you. You may begin. Hello everyone, and welcome to Tamboran Resources Corporation's Financial Year 2025 Fourth Quarter Earnings Presentation. My name is Dick Stoneburner, and I am the Chairman and Interim CEO of Tamboran Resources Corporation, and I am joined here today by 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 fourth quarter has been a period of incredible activity for Tamboran Resources Corporation. We delivered and announced record flow rates from the 5,500-foot horizontal section in the SS2H ST1 well. Importantly, the well delivered an extremely flat decline over the 90-day period, including a surprising 2% increase over the last 30 days of testing without downhole intervention or changes to the choke. I believe we could be seeing the enhanced matrix connectivity achieved during the stimulation program and performance from a formation that has 40% higher gas in place and 20% higher TOC than the Marcellus Shale. In July, we commenced the most aggressive drilling campaign in the history of the Beetaloo Basin. The program includes three wells that have been drilled utilizing batch drilling techniques, each with a 10,000-foot horizontal section within the Mid-Velkerri B Shale. I'm happy to report that earlier this week, we reached total depth on the second of the three wells, delivering record drilling speeds through the horizontal section in the formation. I am also proud to highlight that during the period, we received consent from native title holders to sell gas under the legislative appraisal framework. This is the first approval secured from native title holders under the new beneficial use of gas legislation, allowing us to sell appraisal gas from the exploration permit for three years. The BJV will now focus on securing necessary approvals to support longer-term production. As we highlighted earlier in the quarter, we have commenced a farmout process incorporating approximately 400,000 acres in the most development-ready acreage in the Beetaloo Basin. We've attracted strong interest from a range of highly qualified counterparties who are attracted by the strong technical properties of our acreage and the constructive commercial and regulatory environment. Discussions are ongoing, and we will update the market at the appropriate time. Our board was also strengthened with former Pioneer Natural Resources Director and CEO, Mr. Scott Sheffield and Mr. Philip Pace joining the company as Non-Executive Directors. They each bring extensive leadership, operational, financial, capital raising, strategic partnering, and risk management expertise to Tamboran. We ended the quarter with US $45.2 million in cash and receivables of US $26 million, including US $11 million proceeds from Tranche 2 of PIPE transaction, which was received in July, and US $15 million from an acreage sale to Daly Waters Energy. We are also progressing discussions with financiers to secure the remaining funder of the SPCF construction. Finally, I want to emphasize that our search for a new CEO continues to progress, and we expect to announce the new position before the end of the calendar year. Moving to slide four, during the quarter, we announced record IP 30, 60, and 90-day rates from the SS2H ST1 well. A reminder that the well was tested over approximately 5,500 feet of horizontal section within the Mid-Velkerri B Shale. Rates from the well increased approximately 2% during the final 30 days without changes in the choke or downhole intervention. This may indicate significant matrix contribution and enhanced fracture conductivity. We have continued to compare flow rates from the Beetaloo Basin's Mid-Velkerri B Shale to the Marcellus Shale. However, what we are starting to see is the Beetaloo Basin showing its own distinct character, which may indicate lower decline supported by higher gas in place, higher TOC or total organic carbon, and higher gas saturation. Additional and longer duration testing of these wells will support what the ultimate EUR of these wells will deliver. This is the key reason for the pilot project, and we look forward to providing updates on these longer-term tests once we commence gas sales next year. Moving to the next slide, as I mentioned earlier, we have completed drilling of the first two wells in the three-well campaign. The three wells were batch drilled, meaning we drilled each section of the well separately, which allows for much more efficient drilling operations. This has only been able to be efficiently completed in the Beetaloo Basin using Helmerich & Payne's SuperSpec FlexRig 3. We continue to learn from our drilling operations, and this program has seen the implementation of anti-vibrating technology to address tool failures, as well as modifications to the nut system. These changes have resulted in year-on-year improvement on basin-leading drilling rates within the target Mid-Velkerri B Shale. We have seen a level of tool failure within our drilling program, resulting in non-productive time on the SS4 and SS5H wells. We are continuing to work with our oil field service providers to reduce this non-productive time and improve further on our drilling profiles as we target spud to total depth that is potentially considerably less than 25 days. Moving to the next slide, I want to provide an update on the two infrastructure projects being delivered to transport our additional volumes to the local pipeline network and achieve successful gas sales. Firstly, the SPCF compression and dehydration facility is a Tamboran Resources Corporation and Daly Waters Energy-owned facility that will process the gas ahead of delivering into the pipeline. We secured approval from the Northern Territory Government earlier this quarter and completed the key earthworks on the site. The compressors and the TEG unit have been delivered to the site and lifted to their final locations. Essentially, we have all pieces in place to start the pipework and connections of the facility ahead of completion and commissioning in mid-2026, subject to duration of the wet season. The Stuart Plateau Pipeline is owned by the Australian pipeline company APA Group, which will connect the SPCF to the gas sales point on the APA Group-owned Amadeus Gas Pipeline, which is the local pipeline network in the Northern Territory. APA Group received approval from the government to commence construction of the pipeline and it is expected to be completed by the end of the year. Tamboran Resources Corporation will pay a fixed monthly tariff to APA Group for use of the pipeline. Moving to our cash position, we entered the quarter with $45.2 million in cash, up $20 million following the receipt of cash related to the first tranche from the PIPE transaction undertaken in May. Tamboran Resources Corporation shareholders approved the second $11 million tranche in July. The majority of cash flow related to funding of these SS2H ST1 stimulation and flow testing and the successful SS3H remediation activities. Tamboran Resources Corporation expects to receive the $15 million cash payment from Daly Waters Energy by the end of the year. Our cash balance and receivables are $71.1 million. We continue to move towards securing a financing facility to fund our remaining share of the SPCF infrastructure, and we hope to be able to announce this in the near future. Moving to slide eight, you can see that we have a busy year ahead of us as we deliver on our commitment to commence gas sales from the Beetaloo Basin. If I think back to 15 months ago when we listed Tamboran Resources Corporation on the New York Stock Exchange, we made a commitment to commence gas sales in mid-2026. Since then, with huge credit to our team and key stakeholders, we have maintained this schedule and are getting closer to delivering on this promise. I believe the Beetaloo Basin has the potential to transform not only the Northern Territory, but Australia's East Coast as a whole, delivering energy security to Territorians and a pathway to potentially securing long-term energy security for Australia's East Coast gas market. I want to thank our shareholders for the continued support and look forward to providing an update on our activities at our next earnings call in November. With that, I would like to hand over to the operator for questions. Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press *1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press *2 to remove yourself from the queue. For participants using speaker equipment, it may be necessary to pick up the handset before pressing the * keys. One moment, please, while we poll for questions. Our first question comes from the line of Scott Handled with RBC Capital Markets. Please proceed with your question. Thanks. Good afternoon here and good morning there. My first question is around drill times. These last two wells, you've gotten pretty close to the target 25 days, but you did indicate there were some tool failures. Can you give us a little bit of color on what specifically you've encountered? If you get those resolved, where do you think you can get the drilling days at? That's a great question. We're seeing the typical failures that we see all across North America with horizontal drilling, particularly in rather hostile environments as far as temperature and pressure is concerned. It's tool, it's the rubbery steerable systems, mud motors, the typical downhole failures. What I would tell you is that we've actually looked at the best segments of each well that we've encountered over the last two wells. When you put those best segments together, we're right at 19 days. That gives you a sense, even without additional spudder rigs or oil-based mud or some of the other things that we're planning on doing in the future that will cut drill times as well. We're standing here today with our best well potentially being 19 days. I think it's really positive. That's why I kind of mentioned that I think we could have significant improvement over the 25 to 27 days that we've seen with most of the wells so far. Got it. That sounds great. Obviously, it sounds like you'll be starting to frack the number four well here probably soon at some point. Can you remind us what is the plan for that well? You're going to basically stimulate the well. Do you plan on doing a flow test on that one and then shutting it in to bring the pilot project online? Yeah, that's exactly right, Scott. If we get off this well, you know, call it early to mid-October, we'll immediately demobilize the drilling rig, mobilize Liberty. I think, as you saw when you were there a month or so ago, it's on the corner of the pad right now. It's sitting waiting on ready. It's going to be, you know, very similar to the simulations we've done on previous wells. I think we're talking about maybe cutting back on the water a little bit, potentially going back to the same volume of sand we used on the number one well. Other than that, it's going to be pretty much cookie cutter to what we've been doing on the first two wells. Was there another component of the question that I didn't answer? Yeah. In the flow test, are you going to, you know, do a flow test, an everyday flow test? Yeah, we will. We'll do what we've been doing in the past. We'll do a quick flow down or flow test, drawing down the water. We want to get down to about 150 barrels per million, something like that. Once we see that, we'll shut it in. We're going to continue soaking these wells until proven otherwise. We'll soak it for probably about 30 days and then do a 30-day flow test. That puts us kind of right around, you know, early first quarter, and we should have results. Got it. Thanks. Just one kind of quick follow-up on the completion. When we were out there a few weeks ago, obviously, the sand was already on site. Is all the sand on site, is that ample for the frac job, or are you going to need to bring in more? No, it's ample. We're actually trying to get sand on location for the balance of the wells in the spring. It's an ongoing effort to continue to build up our inventory of sand. As you know, the wet season can make logistics like that challenging. We're going to try and get ahead of it and get our sand on location. That's right. Great, thanks. Thank you. Thank you, Scott. All right. Our next question comes from the line of Khaled Agami with Bank of America. Please proceed with your questions. Hey, good morning, guys. Hi, Dick. Dick, there. Good morning. How are you? I'm going to have to make changes. Good morning. You're now leading the company at what is a pretty critical time here. There is execution of the remaining pilot wells, and you talked about some of the changes that you're making to the forthcoming wells on that path, and that's very exciting. The data room for the farmout is now also open. I think in that setup, there's a couple of questions that are top of mind for me. For the first question, I want to focus on the farmout, and I'll keep this pretty open-ended. Simply, help us understand what a successful outcome here could look like. I'll pause there for a response, and I have got a second question. Yeah, I think it's a little premature to give any specifics in terms of valuation that we might expect. It's an ongoing process. It's a negotiated process. We want to achieve the best outcome that we can for the company. I think you're aware of how much potential value there is in this basin. We're really not going to discuss any specific types of considerations at this point. Just be aware that we've had a good response. We have people that are quite interested in it from a wide range of company types, if you will. We're encouraged. That's about as much as we can say right now. Got it. For my second question, I want to come back to the original business plan where there was an equal focus on domestic gas sales and LNG development. As you kind of take over strategy here and look for the next CEO, are you still interested in pursuing both development opportunities? Both the different markets that are available to us, is that the question? Yes. Domestic gas sales plus LNG development. Are you still interested in pursuing both? Absolutely. There are just different timelines for each of those different markets that are available to us. Obviously, we're going to be selling first gas sometime mid-2026, let's call it that. That will be to the Northern Territory. We're going to continue to ramp up those volumes that could eventually take gas to the Southeast markets. It's going to take quite a bit of infrastructure to get long-haul pipe to the Southeast markets, but that is our goal as kind of phase two. We will layer on those volumes as we finish the completion of the infrastructure toward the Southeast markets. Ultimately, Australia clearly needs additional gas volume for the domestic demand. The type of basin we have here and the opportunity we have in terms of deliverabilities means this additional gas will need to get on the water. That is a long-dated exercise. Is it the initial brownfield on existing Darwin LNG facilities? Is it moving toward a greenfield at Northern NT LNG? I think all of the above are in play, but it's a matter of timing. It's probably a matter of who our farming partner would be. Each of those parties might have a little different view on the most optimal markets, both domestically and on the water. We will certainly listen to what those thoughts are that our farming partner might have. We still have all of the above in terms of market opportunities for us. Really, this is a 10-plus year project where there's plenty of volume to put on the water at that point. I appreciate it, Dick. Thank you. You're welcome. Thank you. Our next question comes from the line of Charles Mead with Johnson Rice. Please proceed with your question. Good morning, Dick, to you and all the Tamboran team. Hey, Charles. Dick, you've talked about the farmout a little bit, and I recognize that it's always sensitive to talk about a process that's ongoing. Can you give us any sense of, you know, at the margin, whether that when you expect to conclude the farmout process? I think your materials say 1Q 2026, but is that when you, you know, are we going to learn about it in 1Q 2026, or is this something that would maybe slide to 2Q? I think the best case scenario is that somewhere around that time, we will have a conclusion and something we'll announce to the market. I really don't want to get any more specific on the timing of that. You know how these processes work. There are a lot of people involved working at different paces. We want to give everybody the opportunity to study the asset as much as they can. I think 1Q 2026 is a reasonable expectation for something we would announce to the market. Got it. That is helpful, Dick. Dick, I also want to go back to this kind of strange but welcome production behavior from the SS2H. You talked about this a little bit in your prepared comments. Do you have any kind of new ideas at the margin that would explain this mystery of how the well was inclining on days 60 to 90? I'm just wondering, I mean, we talked about sand loading, but was there maybe a different sand source that you used in this well versus previous wells? Is there just anything incremental there? Yeah. I don't think the nature of the sand that we pump between the two wells is materially different. I would dismiss that as a likely explanation. I think I might have explained to you in previous conversations that I think it's pointing to two explanations in my mind. One's more geologic in that we'd have a unique set of rocks. Unique is an understatement. As you know, these rocks are four times older than any other shale basin in North America. They're very unique in the fabric in which they were deposited. Without getting into more geologic background, they are very unique. It's the oldest petroleum system in the world. There's nothing like it. I think that does, you know, just connect the dots type analysis without any further statement. I think that does provide some explanations to why there might be a different performance than any of the other shale wells that we've seen in North America or really anywhere else. Secondarily, there could be some reservoir engineering explanations in terms of the flow back. We don't know that yet. Since we shut it in, I think the reservoir engineers would like to see more data to put in their computer and see if they can come up with explanations. I think it's one of the two, if not both. I think both is probably a likely event in any situation like this. It's not one factor. I think there is a unique set of rocks. We'll know more when we put these wells, not just on test, but into production. That's not far in front of us. By, again, call it mid-year, next year, by the end of 2026, when we have a better feel for the decline profile and maybe more explanations as to why. I think that's the time we'll really know, or at least have a lot better data set to make that assumption. Right. That's a helpful elaboration, Dick. Thank you. You're welcome. Thank you. Our next question comes from the line of Jeff Grampp with Northland Capital Markets. Please proceed with your question. Hey, Dick. Thanks for the time. As you guys wrap up the drilling program here over the next, you know, month or so, what factors are at play for timing and magnitude, I suppose, of the next drilling program? Would you say that's largely dictated by the farmout process and the outcome there over the next handful of months, or what other factors are you guys evaluating for the next drilling program? I think the 2026 campaign is largely driven by the farmout process and who our partner is, how and when they want to proceed. I think ideally, we'd like to get started as soon as we could after the conclusion of the wet season. We've got a lot of planning for that. There's a bit of a timing issue to make sure that we're initiating a program that is consistent with the farmout partner's desires. In other words, geologic subsurface decisions. We don't necessarily want to make them arbitrarily, but we also have permits that we've got to get from the government. We've got to get long lead items. There are a lot of moving parts, and we're trying to juggle them as best we can. I think the base answer to your question is, ideally, we're bringing the rig back on location to the appropriate pad, call it second quarter of 2026. Great. That's really helpful. Does that answer your question? Yep, that's perfect. Thank you. For my follow-up, it sounded like, on these upcoming wells, the completion design is not really going to change that materially, if I heard you right from the earlier question, Dick. On the production side or how you flow these wells, is it a similar answer there, or has anything from the 2H maybe given you, given the team some thought on, you know, how you produce these wells in the early days from a choke management standpoint? You took the words out of my mouth with choke management. I think we were a little more deliberate with our choke management and overall production practice on the 2H. I think it may have a bearing on the performance. As you know, being involved in shale as long as you guys have, you can't change very many things at one time and really know what provided a different outcome. In this case, we're kind of focusing on water. As I mentioned, obviously, these are very, very old reservoirs. It's highly desiccated, and there's really no water in the system whatsoever. That's what basically desiccation means. When we pump water, it basically is absorbed by the rock. That's part of the reason why we soak them, to get that imbibition, which creates the water being absorbed into the rock fabric and then the gas coming out as a replacement for that. Because it's desiccated, we don't feel like we need as much water as, say, a typical North American frac in the Haynesville. I think Haynesville designs now are upwards of 100 barrels per foot or more. We pump 50 barrels per foot. We're going to dial that back a little bit, I think. I think that's the primary change. Our sand volumes are often loading on the two wells. We're not all that different. I personally don't see a great element of those sand volumes creating a difference. We're going to land probably somewhere in between the two. I think one was around 2,200 and one was about 2,800. I think those are the bookends for sand loading in this reservoir. I do think the team is leaning towards, like I said, less water, and we'll see how that results. Also, the choke management and maintaining a very deliberate management of the choke as we test it. That's really helpful, Dick. I appreciate the time. Thank you. You're welcome. Thank you. Our next question comes from the line of Anish Kapadia with Hannam. Please proceed with your question. Hi, Dick. I had a few questions, please. On the SPCF funding, I just wanted to get a quick update on that. You're still kind of thinking about selling that down or debt funding that. On the back of that, will you be fully funded to first gas? Second one, just in terms of, I suppose, some of the nearer-term upside potential from the current plan of 40 million cubic feet per day. Within the local market, it seems like there is still some further unmet demand or other potential. Just wondering in the maybe 2027, 2028 timeframe, whether there's potential to then sell more gas into that local market. Just a final one. Go ahead. Yeah, just one final one on EP161. I saw that Santos is planning to drill in the middle of next year. Just wanted to see your thoughts in terms of that acreage and your participation in that. Thanks. Great questions. Let me pass the first one over to Eric. He's much more involved in those in the SPCF. Eric, why don't you take the first question? Yeah. Hey, Anish. How are you? We're still pursuing the infrastructure debt facility, and we've spent about $20 million gross with our partner, Daly Waters Energy, to date. The balance of that funding needed, as we communicated to the market, is about $70 to $80 million. We're walking down that path. There's very good interest in these assets. I mean, this is very much a basin-opening infrastructure play. Remember, this is under our beneficial use of gas. It's not as a permanent fixture, but you're absolutely right. There is opportunity to provide more gas into that market and additional demand. I think the current planning is to get the infrastructure facility in place, get the funding for that in place. There are several parties that we are in discussions with that we could either sell it down, sell down a portion of it, subject to approval and working with the native title holders and under the regulations that are in the territory, expand that production facility for really a modest incremental cost to double it. The economics, as you know, are scalable. They just get better and better as we expand into that market, that unmet demand. Does that answer your question? Yeah, that's great. Thanks. Yeah. Let me pick up the Santos EP161 question. We're excited about, you know, drilling wells over there. I think, as you know, there's two depot centers in the basin, one in the Shenandoah area, much larger than EP161. They're equally good in terms of pressure, reservoir quality, number of benches available to us. We're really excited about Santos's drilling program for 2026. As we understand, there will be two wells drilled. Any more details on those wells would probably be best served coming out of Santos. I'll just tell you that we are planning on participating in those wells. We look forward to them. It's been a while since a well has been tested over there, about 2021, if I'm not mistaken. We can improve on that well design significantly to probably deliver considerably better results. Again, really excited about it and looking forward to partnering with Santos on the wells. Any other questions? Okay. Good. Thank you. Thank you. Our next question comes from the line of Paul Diamond with Citi. Please proceed with your question. Thank you. Good morning. I'm here second to call. I just wanted to get a quick kind of touch base on, the native title holder agreement is for three years. How should we think about that next round of negotiation? Is that just an extension? Is that back to the table? Are you looking for a longer duration? Just kind of think about what comes next there. I'll start the answer with a broad statement and let Eric provide more color. There are very specific processes we need to undertake with the native title holders as we move toward a production license. It's very deliberate. It's prescriptive. It's something that will defer to every need that the native title holders are granted. Eric, do you want to pick up and give more detail on those processes and how we work through them? Yeah, it's a good question, Paul. We have three years to be able to sell gas and the appraisal from the beneficial use of gas legislation. This is really to avoid flaring during the appraisal process. As you know, the local demand is there, so it's a win-win for everyone. We've commenced or are commencing discussions to secure the Indigenous Land Use Agreement. It's an ILUA, is the acronym. I know it's a little difficult, but this is a very normal period of consultation. It can take anywhere up to three years where you're having meetings on country with the right government authorities in the room. It's a process of what do you expect, what would we like to do, how does it provide local jobs, royalties, all the things that go into that type of discussion, as in any mining project or oil and gas project in Australia. When you get through that, that provides you with a production license. That's really your HVP, right, for the American equivalent. It's an important nuance, and you asked the right question because this whole three-year period is under a temporary agreement. That is really to avoid flaring. I mean, flaring is not, we need the data, but flaring is not good for us, for the environment. It's loss of revenue. We're really, really proud of the Northern Territory government and the forethought they put into this while we're going to be working on the longer HVP strategy with the native title holders. Got it. Makes perfect sense. Just a quick follow-up. You guys have talked previously about trying to find a way, whether it's, you know, in post-phase or post-pilot or Phase Two, to getting more of a local sand solution in place. Just wanted to see, is that still in the plans for Phase Two and how we should think about the progress there? Yeah. Local sand is obviously a key focus of ours. Every single basin, I think, in North America has evolved to provide local sand, some more local than others. We have done extensive testing throughout the basin with the auger test to get some idea in terms of the quality of the sand. We need to know what its compressive strength is. We need to know what the grain size and the variability in the grain size is. There is a lot of that initial research, if you will, and that's kind of where we are. There are certain procedures that we'll need to follow to affect a mine in the long run. We're working with some of our partners such as Liberty who have had experience in this and guide us through the process. I think rest assured that we have every intent to use local sand, but we need to make sure we follow both the technical analysis and any procedural analysis we have to do from a governmental standpoint. Does that answer your question? Makes sense. It does. Thanks for your time. I'll leave it there. You bet. Thank you. Ladies and gentlemen, we have reached the end of the question and answer session. This does conclude today's conference. You may disconnect your lines at this time. Thank you and have a great day.