Greetings and welcome to the Tim Bourne Resources fourth quarter fiscal year 2026 earnings call. At this time all participants are in listen-only mode. A question and answer session will follow the formal presentation. You may be placed into question queue at any time by pressing star 1 on your telephone keypad. We ask that you please ask one question, one follow-up, then return to the queue. As a reminder, this conference is being recorded. If anyone should require operator assistance, please press star zero. It's now my pleasure to turn the call over to Todd Abbott, Chief Executive Officer. Todd, please go ahead.

Hello, everyone, and welcome to Tamboran Resources Financial Year 2026 Fourth Quarter Earnings Presentation. My name is Todd Abbott, and I'm the Chief Executive Officer of Tamboran Resources. I'm joined here today by Chief Financial Officer Eric Dyer and VP Investor Relations and Corporate Development, Chris Morbey. I'll start by reviewing delivery against the commitments we made 12 months ago, then cover production and commissioning as we build towards plateau rates and contracted supply. I will also discuss what our latest well results and operating improvements mean for performance and cost as we continue to de-risk our asset. I will then review our funding position and close with the next development milestones before we take your questions. Moving to slide two, you can see our disclaimer, which relates to forward-looking statements within the presentation. I encourage you to review those at your convenience. In slide three, the last few months have been a pivotal period for Tamborne and the Beetaloo Basin, as we have delivered on a key commitment and provided the next step in de-risking the basin. We have delivered first gas sales from the Beetaloo to the Northern Territory gas market. Homes and businesses in Darwin are now being powered by a local onshore resource. These gas sales also bring royalties to the Northern Territory government and native title holders, alongside job opportunities for Territorians. Tamborne already employs a significant local workforce, which we expect to grow as activity increases over the coming years. Moving to slide four, gas has now been flowing into the market for 20 days. Volumes are currently limited by market demand, with the Northern Territory government nominating 25 terajoules per day as the territory comes out of its lower demand season. We expect demand, and therefore nominations, to keep growing through the Northern Territory's peak demand period. We are currently in the commissioning period of the gas sales agreement. Once the agreement moves into the supply period, take or pay provisions will apply to the 40 terajoule per day contract quantity. and we will be getting revenue based on that 40 terajoules per day. Any gas the off-taker does not take will be banked for future potential delivery. This gives us downside protection in the event of lower nominations during the contracted period. Regarding our flowback strategy, we will prioritize two wells to ensure that we're generating long-term production and well performance data to further de-risk the basin. The remaining wells will be managed as needed to recover flowback water and to close any gap to the allowable nominations. In achieving this first gas milestone, our operations team have been working deliberately across multiple work streams. They successfully completed the stimulation campaign on the SS2 pad in the Beteloo Basin. The program utilized the Liberty Energy Stimulation Fleet that was imported into the basin in 2023. During the program, we completed 178 stages across 30,000 lateral feet. It was the largest stimulation campaign conducted in the basin. And the zipper-frack approach allowed us to achieve 20 hours of operations and a Beteloo Basin record 12 stages completed in a day. This gives us and the market early evidence that we can execute completions more efficiently. The next measure of success is sustaining an improved pace across a full campaign Reducing downtime and bringing down completion costs per well. We have also entered into a non-binding memorandum of understanding with Liberty Energy, setting out the intent to extend the hydraulic fracture stimulation and wireline services agreement covering Tamborne's operations in the Beteloo Basin. Liberty intends to begin phasing lower emissions pumping equipment into the Beteloo fleet from 2027. Importantly, The campaign included 10 stages using the locally supplied Beteloo red sand across various locations within the SS2 5H well. The pumping and placement of the local sand was an identified risk going into the program. However, given we experienced no impact to pump pressures or fracture initiation during these stages, we are confident on our ability to place local sand in future campaigns. Tracers across the horizontal length have shown that the stages are producing in line with offset wells, but these are still early days, and the true test will be the longer-term flow rates and recoveries. We plan to further test our beetley red sand during the upcoming stimulation program planned on the SS1 pad. Success of that local sand is a key step in delivering near-term cost reduction for well completions. It is expected that that sand could save 4 million U.S. per well with a 10,000-foot horizontal section compared to the sand imported from overseas. Those long-term flow rates and recoveries from those stages will help us assess how widely we can apply those savings. In conjunction with the upstream activity, the operations team successfully completed construction of the Sturt Plateau Compression Facility on time at approximately 9 million U.S. below the forecasted budget. This allowed us to meet our commitment to the supply of the Northern Territory gas market during the quarter. The commissioning of the facility remains ongoing as we fine-tune control systems and refine equipment settings. During the commissioning period, we will be receiving 75% of the gas price. This is due to the interruptible nature of the supply. Once commissioning and production testing requirements are complete, we will commence delivery into the take-or-pay contract with the Northern Territory government. During the quarter, the operations team also commenced drilling the three-well campaign on the SS-1 pad with the H&P Flex III rig. Drilling of the first two wells has been completed, with the third well currently drilling ahead. We continue to incorporate lessons from previous campaigns. This program includes first wells drilled with our improved drill bit design and anti-vibration tools. This resulted in record speeds through the Morocco mission. Modifications to the rig have resulted in reduced mud temps, allowing increased average ROP in the lateral sections. We continue to work with our contract partners to improve efficiencies and reduce downtime, especially within the lateral section, and we believe these are addressable as we ramp up activity. In the east, drilling of the two-well appraisal program with Santos on EP161 has also commenced with the Jabera South 1H and Newcastle South 1H wells in that depot center. During the quarter, we significantly strengthened our balance sheet. In April, we raised U.S. $186 million net of fees via an underwritten public offer and an institutional and retail entitlement. The funds from the raise solidified the balance sheet and provide us financial flexibility. At the end of the quarter, Camborne had U.S. $225 million in cash and $31 million U.S. in undrawn debt for funding of the SPCF. including the U.S. $15 million that we expect to receive from Daily Waters Energy, the pro forma cash position is U.S. $240 million. Receipt of that $15 million remains subject to certain conditions precedent. Over the next two quarters, we expect that under U.S. GAAP, some revenue and costs related to the pilot project will be capitalized to the balance sheet during commissioning rather than flowing through the income statement. This is to avoid reporting volatility and means that the income statement will not reflect cash movements during the period. We expect to announce first quarterly gas sales and revenue in our 1Q fiscal 27 earnings in November. The next phase of our development plan is to further delineate our gas resources across both depot centers in the Bentley Basin. This will be the focus of our 27 and 28 campaigns. We are working with our joint venture partners, Daily Waters Energy and Inpex in the West and Santos in the East to drill and stimulate at least six step-out wells over the next 18 months. We are progressing discussions with multiple parties to bring in a strategic partner. These strategic discussions and the upcoming appraisal work aim to align on resource delineation and commercialization pathways that will support a large-scale development and underpin new pipeline infrastructure. That infrastructure is expected to connect the Beadley Basin to multiple high-value markets. To close, we have delivered the first gas sales that we committed to 12 months ago and completed the compression facility on time and below the forecasted budget. Our latest drilling and stimulation work is showing where we can improve efficiency, while local sand offers a potential source of completion cost savings. The equity raise has strengthened our balance sheet for the next phase of development. The priority now is to turn those achievements into sustained operating performance. That means completing commissioning and production testing, building towards plateau production and contracted supply, and demonstrating that the gains in well delivery can be repeated. Those are the measures I will use to judge our progress as we advance our development plans and partner discussions. As we close, I want to thank all Timborn employees for their commitment, their performance, and their support for one another as we continue to grow, evolve and deliver for our customers and shareholders. Thank you.

Thank you. We'll now be conducting a question and answer session. If you'd like to be placed in the question queue, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. If you'd like to remove yourself from the queue, please press star two. We ask you to please ask one question, one follow-up, then return to the queue. And that's star 1 to be placed into question queue. Our first question today is coming from Scott Handel from RBC Capital Markets. Your line is now live.

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

Yeah, Scott, good to hear from you. Good question. On the 6H and maybe even more broadly kind of on the total drilling program, like the recent changes you'll see there, and I referenced it in the remarks there, the bit design on some of the kind of upper level zones there that we were going through, the vibration damper was actually a pretty big change for us, so that's helped us quite a bit. I'll also add like one of the things that isn't really a tool change but the directional plans on those wells and that the way we attack that in a rope sandstone which is just a really hard zone just hard rock to get through so that's been one of the areas where we saw the biggest opportunities and in that last well we got through it with one bit which was a big wind force earlier wells initial wells on this had many more bets trying to get through that zone so That's been a key improvement for us. When we look at the opportunities going ahead, we think improving time on our downhole tools is going to help us a lot. We do see opportunities eventually to go to a synthetic oil-based system, which will help our drilling times as well, the ROPs. And then there's going to be a lot of little things. I mean, I think you've heard me say this before, ultimately, to really get the drilling times and those costs down where we need them to be, We need two things. We need repeatability, so just doing the same thing, same crews, doing it again and again and again. And then the other is scale across the basin. So this is all operators, but having enough critical mass of activity in the basin so that service companies have their center of operations that can be efficient in the way they set up their operations so that we have readily available tools, readily available equipment, people, skill sets, logistics all work better. Everything we've seen in these large shale plays in the U.S. will eventually happen here. But those are the two things to really get it down into those kind of U.S. level cost structures.

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

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

Appreciate that. Thank you.

Yeah, no worries, Scott. Thank you. Next question is coming from Leo Mariani from Royalty Alliance. Hey, Leo.

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

Yeah, and we'll get Chris to kind of go through the specific numbers on it. But I'll tell you at a high level, we've got four wells in the pilot area. You'll see three this year, one next year. We've got the two Santos wells over EP161 with our 25% working interest. Trill this year, Simulating next year. And then we've got the four wells in the BCDA with daily waters. It's about a 10% working interest there. So, I mean, overall, you can expect our capital to be focused on de-risking. And frankly, the full capital program isn't going to be fully locked in until we finalize who our partner is and align those, what I would call, collective strategic priorities. Kind of where we're going to be in both basins, as you can imagine, each potential partner has a little bit different focus, either one depot center or the other, or for some both. So as those conversations evolve, we'll lock the rest in.

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

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

Thanks. Yep.

Thank you. Next question is coming from Jeff Cramp from Northland Capital for Market Control. How does that last?

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

Yeah, so first I'll just kind of talk about the early performance. And I mentioned in the remarks too, we had no problems pumping the sand, which that was something we were watching for. We started the fracks, like initiated the fracks well with it. So we're highly confident in our ability to pump it. When we look at the tracers coming back from those stages, they look identical to the other stages and the other wells. So early results are positive. But just like with the production, we won't know the full answer until we get some production history on this and see how all that holds up. So yes, we're optimistic on what it can do. With regard to these next wells, we won't move to a full red sand program until we are confident in it. So we need some of that history. Each well we drill out here is pretty important to help de-risk the basin. So we're not going to kind of take outside risk on any one of them. So we'll do some additional stages on these next completions, but we won't do full wells at this point. Jeff. Going forward, once we get history on it, once we're comfortable that the B-Loo red sand does what we expect and hope it will do, I can see us going to a 100% full program of red sand or effectively 100%. There could be some supplements here and there. I think the end goal is to use in-basin sand in the B-Loo. From a low-cost perspective, it's going to be the obvious right thing to do.

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

Yeah, I think all the things you're mentioning are important inputs on it, although I feel pretty good about all the ones you mentioned. The one that we really have to look at, and this is probably the key uncertainty on whether we expand it or not, is making sure that the surrounding infrastructure network will allow us to move the incremental volumes to the incremental markets, just having high confidence that we can get that. We don't own the pipelines all around us, and understanding how the gases are going to flow and how those are going to be upgraded or modified over time will help us make the decision. So we're working through that now. kind of getting a better understanding each day on it. But that's something we just need certainty on before we make that kind of investment. We need confidence that we will be able to do it.

Understood. I appreciate the time. Thank you.

Yeah, no, I appreciate it, Jeff.

Thank you. Next question is coming up from Charles Mead from Johnson Rice. Your line is now live. Hey, Charles.

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

Yeah, and Charles, just to make sure I understand your question, you're asking when can we get, like, you know, it's about $25 million now, but when can we get up to the $40 million take or pay? Okay.

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

Yeah, okay, I understand your question. So, yeah, on the nominations, right, so the NTG, the Northern Territory Government, nominates the gas that they need, right? So right now, because of just where they are seasonally, those needs are not high. So they've limited us to 25 terajoules a day for most days. That will continue kind of in the near term. As they move into the, you know, into the wet season and as temperatures rise, you're going to see that load increase, their power generation load increase, and thus their gas demand increase. But just to be clear, and I think I said this clearly earlier in the remarks, and not exactly your question, Charles, but for everyone else's benefit, the $25 trillion a day is a Northern Territory government limitation, not a well delivery. We're meeting that now. We prioritize the two wells. Exactly what you're saying, our priority is on generating well history and performance data for these wells long term. So we prioritize the two wells. We expect as we move through towards the end of this year that nomination is going to go up. We're going to get more wells under that, but to start with, we're prioritizing those two. And the wells we're prioritizing are, you know, full 10,000 foot lateral and then the well with the fetally red sand so that we can get clarity on that data. I think probably by the end of the year, we'll see up at that, you know, I'm kind of, predicting a little bit what they're going to nominate that $40 trillion target. So we'll be able to get more wells in there, Charles, but it's hard to say exactly. But then later, as we go into next year, we should expect the seasonal restrictions to kind of come back in, and we'll have to pull some of those incremental wells offline. So you won't get the full kind of You know, 12-month history on the other wells, but we are going to prioritize at least two so that we can really see the long-term history of what the wells do. Am I answering your question? I feel like I muddled through that a little bit.

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

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

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

Got it. Thank you for that detail.

No worries, Charles.

Take care. Thank you. Next question is coming from Paul Diamond from the city. Your line is now live. Hey, Paul.

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

Yeah, I mean, I would say the real impact of the red sand is really in development mode, right, where your capital intensity is higher, we have more wells going in. So we certainly want to have that answer before we get into a development mode. We want to use increasing tests as we go forward. What we're specifically looking for in this is to make sure that the zones where we place that red sand hold up on a relative contribution basis over time. right so you can see situations where as the reservoir drawdowns and as those stresses change down hold that you know the crush pressure for light that's not a technical term but but can kind of increase over time we want to make sure that this sand holds up the way the other zones hold up so that's what we're looking for we're looking for relative contribution across those different zones and make sure they're comparable and as long as they are the cost differences are dramatic will stay with the local SAM.

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

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

Appreciate the clarity. I'll leave it there. Yeah, no worries. Thank you. Next question is coming from Anish Kapadia from Hannon. Your line is now live.

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

Yeah, so your question is specifically East Coast?

Yes.

Okay.

Yeah, look, I think APA has been out there pretty actively talking about their work on the East Coast Pipeline. they've done a lot of work on both the permitting side and the right-of-way acquisition or easement acquisition to get that and are fairly well progressed. So high confidence that's moving to their credit. They're not really waiting. They're charging ahead on it. From a sequencing standpoint, the way I see that developing is this. You'll see additional work, like the production data that we're putting on the board from the pilot area It's probably the biggest piece of information to de-risk the subsurface. That's what everybody and everyone on this call and everyone within Tenborne are waiting to see. But that will demonstrate the well decline and the longer-term nature of these wells. Then you've got the other wells that are going in this year. So the two wells over EP161 are going to be important. The other wells and the rest will also correlate. Then over time, and kind of referencing this with our JV process again, there will be other work programs that come out and delineate additional resource. But ultimately what the industry has to do, and I say that meaning broader than just Dan Boren, is collectively our work will de-risk the resource to merit that infrastructure investment. And that can happen fairly quickly. The resource out here is such that it doesn't take a lot of wells to identify a pretty large resource and to merit that large infrastructure investment so that East Coast Pipeline with APA doing their work and with us doing the upstream work, it really de-risks the investment. And we all know that the LNG exists on the East Coast and the needs both in the domestic market and in the LNG facilities over there. So GSAs, early conversations are already happening, but there's nothing binding that's going to happen until you have very clear resource. So I hope that's helpful. That's kind of where the sequence is. It's a little bit hard to say exactly what that timing looks like, but that's the way the sequence will work.

Thank you. I thought that was a good update.

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

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

Thank you. That does conclude today's teleconference and webcast. You may disconnect your line at this time.

and have a wonderful day.

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