Tamboran Resources Corporation

Greetings and welcome to the Chamberlain Research's third quarter fiscal year 25 earnings release. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Joel Whittle, Chief Executive Officer. Thank you, Joel. You may begin.

Thank you and welcome to Tamborne Resources' third quarter fiscal year 2025 result presentation. I'm Joel Riddle. I'm the chief executive officer for the company.

And joining with me this afternoon is Eric Dyer, chief financial officer.

Before we get into the material, I'd like to refer everyone to the disclaimer statement on slide two associated with forward-looking statements. Starting on slide three with key highlights from the quarter, the company successfully completed 35 stages in this insurance OSF 2H well. In following an extended 62-day soaking period, the well has commenced a flow test in which we plan to report an IP30 flow test to the market by the end of June. Overall, we plan to flow the well a full 90 days, and we'll be reporting an IP90 to the market by the end of August. Following the completion of a capital raise that we announced to the market yesterday, we are fully funded to complete the drilling of three follow-up pilot wells, Shenandoah South 4, 5, and 6. Those wells will be drilled in second half of 2025, targeting flood of the SS4H well in early July. Following a review of the previous two wells that we have drilled off the same well pad, Shenandoah South 2 and 3, we will be targeting a 25-day spud to TD timing and demonstrating an increased cost effectiveness for the 10,000-foot horizontal wells that we plan to drill. Once the drilling is completed for these three wells, we will be pumping 240 stages with a batch completion across the three new wells. plus the Shenandoah South 3 well, and these completions will take place later this year, moving into first half of 26, ahead of establishing first production of our Shenandoah South pilot project. First gas remains on track to deliver initial 40 million cubic feet a day to the local Northern Territory gas market by middle part of 2026. And also following the completion of a checkerboard negotiation with our partner, Daily Waters Energy, we are now targeting the initiation of a farm out process, a 400,000 acre block, an area we call the phase two development area. That farm out process has initiated and we plan to provide further updates on that farm out process through the balance of this year. The company ended the quarter with a cash balance of $25.6 million, and following the completion of our capital raise yesterday, the company has a pro forma cash balance of $96 million, and most importantly, will be fully funded to deliver our Shenandoah South pilot project in the middle part of 2026. Moving to slide four and a further update on our Shenandoah South pilot project. As I mentioned in my opening statement, Shenandoah South 2H was successfully completed across 35 stages last quarter. And following a 62-day soaking period, the well was opened up and we have commenced flow testing of this well. We plan to report IP30 flow test results in June, and we plan to test this well a full 90-day period. In parallel with the Shenandoah South 2-H flow test, we will be flooding the first of three wells starting in July, Shenandoah South 4, 5, and 6, with the intention to test the minimum of one of those wells over a 30-day period later this year ahead of first gas for the Shenandoah South pilot project in mid-2026. Moving to slide five to provide additional color and detail around our flow back strategies for our Shenandoah South 2H well. First, one of the key learnings that we've seen from recent Beetaloo wells, particularly our Shenandoah South 1H well, is that we've seen productivity improvement after initial gas breakthrough to have an extended stud-in period, otherwise known as soaking. For Shenandoah South 1H, we had a 21-day soak period in which we saw a material productivity improvement from pre-soak to post-soak and moving into our 30-day well test. We believe this is due to the highly desiccated nature of the mid-noctuary shale in which we're looking to develop. This shale is five to ten times more desiccated on average versus U.S. shale basins. The company has taken an extensive modeling review with CoreLab in which has resulted in guiding the company to perform an extensive soaking across the SS2 well. That study has indicated an optimal soaking greater than 60 days. We left the well shut in for 62 total days, and we believe that will enhance the overall productivity given this longer soak period. Moving to slide six, The other extensive review that the company has done following the results of Shenandoah South 2 and 3, we have identified multiple opportunities to further progress cost efficiencies across the next three wells. We've identified three major areas in which we believe can be implemented in these upcoming wells. First, there's an opportunity to batch drill the top hole sections over these three wells. We've also reviewed and optimized bit design and directional tools that we believe will result in material reduction in days across our wells. In addition, we've identified improved systems that will limit nonproductive time. And combined, we believe we will be in position to target a spud to TD timing of less than 25 days for our Shenandoah South 4, 5, and 6 wells. Moving to slide seven provides further detail around the completion of our Shenandoah South pilot wells for later this year. Once our Shenandoah South 4, 5, and 6 wells are drilled, we will move into completing each of those three wells in addition to the Shenandoah South 3H well that is currently duct on the well pad. On these four wells, we will be pumping a 60 total stages over a 10,000 foot horizontal section. And we will have the opportunity to implement key learnings from our Shenandoah South 2H flow test performance and also the tracers that we pumped over across 35 stages. These warnings will inform our profit placement strategy for pumping each of our 240 stages on our four upcoming wells. In addition, we have the opportunity to use local sand in these four completions And the company will be targeting pumping greater than five stages a day using zipper fracking techniques with our Liberty Energy equipment on site. Moving to slide eight, the company continues to make excellent progress around maintaining its schedule to deliver first gas from our Shenandoah South pilot project by mid-2026. You can see we now have the pipe that has arrived in the Port of Darwin. That site will be tied to our Stewart Plateau pipeline that is roughly 23 miles that will be built by our partner APA and connected to the existing Amadeus gas pipeline feeding gas into the local empty market. In addition, we took receipt of a contractor unit in Brisbane in April of this year. That facility will be mobilized to site, and this Stewart Plateau compression facility will be looking to commission later in the year ahead of our first production date in mid-2026. Moving to slide nine, the company also in parallel continues to evaluate expansion opportunities for our phase one business plan. We've identified, again, working with our partner, APA, Up to 90 million a day of additional capacity that we could look to develop through existing pipeline infrastructure. Over the quarter, the company signed an LOI with Arafura Rare Earths, which is a critical minerals project in the Northern Territory, to deliver up to 26 million cubic feet a day for 10 years. The company will be looking to convert that LOI to a binding agreement by the end of the year. In addition to the Aerofuro opportunity, the company will continue to progress discussions with various gas buyers in the Northern Territory and the area in Queensland of Mount Isa, where we see up to 90 million cubic feet a day of demand occurring in the next few years. Moving to slide 10, over the quarter, the company also completed a checkerboard process with its partner, Daily Waters Energy. The results of that checkerboard process is included by the map shown on the right in which Tamborin operated acreage is included in blue. One block I'd like to highlight as part of this checkerboard process is the Phase II development area, which is approximately 400,000 gross prospective acres in which Tamborin approximately owns 58% and operates. The development strategy for this Phase II development area will be to supply the East Coast domestic cash market by 2029-2030 to address anticipated shortfalls that could exceed a BCF in May later this decade. The company has appointed RBC Capital Markets to lead a formal process to farm out Panborn's working interest in the Phase II development area. RBC has now commenced this farm out process and we'll be providing further updates on this process throughout the course of this year. Moving to slide 11, company ended the quarter with a cash balance of $25.6 million, and following the completion of the $70 million capital raise that we announced to market yesterday, the company currently owns pro forma of this deal, an adjusted cash balance of $96 million. This cash will be directed primarily for drilling and stimulation activities for our upcoming three-well program and also the SS3 completion that we will be performing in the next 12 months. The company is in advanced discussions around finalizing terms for potential financing of our SPCF, and we will look to provide further details on the results of that financing in the months ahead. As mentioned previously, RBC Capital has been engaged to commit the farm down process for our phase two development area that we believe will result with a successful farm out, potential for additional cash and to support additional delineation ahead of a project sanction decision on our phase two development. Moving to slide 12, over the next 12 months, there will be multiple catalysts that the company will be reporting to market. starting with the results of our IP30 flow test that we'll be reporting to market in June. In July, we will commence the drilling of our three-wheel program, that being Schoenert OSL 4, 5, and 6. Following the final investment decision for our SS pilot project, we will commence construction for the SPCF and the SPP later this year. And in parallel, following the drilling of SS 4, 5, and 6, we will stimulate All three of those wells combined with SS3 can take a 30-day flow test on a single well by first half of next year. Again, we remain on track toward delivering first gas from our SF pilot project by middle of 26.

With that, I will turn it back over to the operator for Q&A.

Thank you. We will now be conducting a question and answer session. If you would like to ask a question, please press star 1 on your telephone keypad. The confirmation tone will indicate your line is in the question queue. You may press star 2 if you would like to remove your question from the queue. For participants using speech or equipment, it may be necessary to pick up your handset before pressing the star key.

One moment please while we poll for questions. Thank you.

Our first question comes from the line of Jeff Grant with Northland Profitable Markets. Please proceed.

Hey, guys. Thanks for the time. I was curious, given all these efficiency gains and opportunities you guys have identified for the 4H through 6H wells that will start drilling in a few months here, do you guys have kind of a targeted well cost or AFE for those that you could share the potential about yet?

Yeah, sure. So the AFC for these wells would be approximately 28 million U.S. That is what we're AFCing. However, we believe there's material cost efficiencies that we'll see with multiple wells going down. You know, we long-term believe that we can get well costs down, both drilling and completing, down to about $15 million. That's what we've got in the market, too. So over these next three wells, we'll be looking to, you know, demonstrate gains toward getting to that $16 million number. There's really three main areas that I think will come from the cost savings. One is improved ROP. We've already mentioned the optimized mud system that we implemented after the SF2 well. We continue to make progress around refining both the mud system and bit design. I mentioned in my comments improved directional tools. We think that's going to generate potential for the horizontal section to be drilled, you know, in a more efficient way. The last SF3 well, we took 12 1⁄2 days. We think that horizontal section can be reduced to less than 12 1⁄2 days. And then on the completion side, I think the biggest opportunity to reduce well cost over the 240 stages that we're going to be pumping is really sourcing local sand. That's something the team has been very focused on in the last quarter. We've confirmed that we have sand, crack quality sand that we've identified very close to the pilot pad. And We have a real opportunity across the 240 stages to use some of that local sand. To give a sense of the impact, right now our sand costs in the previous two wells have been $4 million. With a local sand solution, we can drop that $4 million cost to about a half a million. So $3.5 million come off those well costs with sourcing local sand alone. So we're very excited to have a three-well program. I think it sets us up to really make a lot of progress around reducing costs. That's something the company has been focused on. And now, you know, I think we have a plan now to get these well costs down pretty dramatically as we move forward.

Perfect. I appreciate that. That's always helpful. A follow-up on the first gas target for mid-26 here. Can you touch on kind of, I guess, the long lead items from a supply chain or regulatory standpoint that present potential risks to that timeline? Or do you guys feel like that's in pretty good shape given, you know, you've got the pipe and things seem to be progressing on the development front as well?

Yeah, absolutely. Really good question. I think first, you know, we've been planning for this second half drilling program for many months. So we've taken... you know, the opportunity to put a lot of the long leads under option. And so I would say there's very limited supply chain issues around getting necessary equipment out to site. You know, the facility, the pipe that APA had sourced has been, you know, right on schedule. So there's really no, you know, no hangups around the timeline, around the facility or the pipelines. or any of the long leads tied to the wealth. So I'm really comfortable around maintaining the timeline. And we're very fortunate to be in a position where Australia is not in the middle of this trade war that many countries are facing. We're trying to take advantage of that being in Australia and sourcing, you know, steel that's on the market at competitive prices.

Great. That's really helpful. I appreciate that, Joel, and I'll let them all stop on. Thanks for the time. Thank you.

Our next question comes from the line of Kayla Attingham with Bank of America. Please proceed.

Hey, good morning, guys. Hi, Joel. Hey. For my first question, I want to ask on the use of proceeds here. Between the pipe and the acreage sale, you secured about $70 million of funding. Our understanding of the original funding path, if you will, was to flow the wealth and then market the results for the capital. So why preempt the plan and seek the capital now? And I'm wondering if this has any read-through to the productivity of the wealth

Yeah, good question. Look, we took advantage of, you know, where we've gotten to with our strategic partner, Formentera. You know, as I mentioned in the opening comments and also in the announcements from yesterday, you know, we have been advancing a negotiation on the checkerboard strategy. And, you know, part of that negotiation has resulted in a $10 million commitment from Formentera and the pipe and also the acreage deal. And we used that as a catalyst to build a $55 million book on the pipe. And, you know, that was largely taken up by existing shareholders and that's in the top 10 shareholders of Tamborin. So, you know, this was You know, a real opportunistic capital raise that puts the company in a very strong position to be fully funded, you know, going into the well test result. And then, obviously, allows us to drill these next three wells to get into production and cash flow for the business. I wouldn't have any read-through. I wouldn't suggest there any read-through on where we are on the well test. I think this is all about ensuring that the company gets into a full funding position for our Phase 1 pilot project. And I'm really excited with the results now to be in a position where we're fully funded.

Okay. That's really helpful. For my second question, I'd like to address the new acreage map. And this one has two parts. First, it looks like the northern and the southern pilot areas are about 20,000 acres each. And if I kind of magic ruler that, it looks like you've retained about 160,000 acres in the very best part of the West. Can you kind of talk about an idealized scenario? And I suppose if Barcell contains enough resources to support multiple BCF per day of production, can you kind of talk about the upside case and the full development scenario? And the part two to this question is, kind of returns to the map and addressing the white space. I suppose now somebody else operates the other part of the white space here on this map. With multiple operators in place, do you see learnings in the basin kind of accelerating here?

Yeah. Yeah, great questions. You know, first, on the 160,000 growth acres that you referenced, being in the, you know, very best part of the Beetaloo West area, you know, just to give you a sense, over 160,000 acres, we can drill around 430 wells. We have three zones, three stack pay zones. They're in that area that we can put up to 1,300 wells in. When you assume kind of an average EUR per well, you can comfortably fit about 20 TCF in that 160,000 acre area. So 20 TCF is enough reserves that we could develop two VCF a day for 20 years. That's our business plan with some headroom. So if you think about two VCF a day for 20 years, that's about 15 PCF. But just within confines of that 160,000 acre area, we can produce that two VCF a day for 20 years plus an additional five PCF headroom. You know, that's something that I would say we are very comfortable on from a near-term development perspective. It's one of the reasons why we call this the Phase 2 development area is that will be the focus of the company, and obviously we want to direct potential farmland partners to that opportunity to work with Tamborin and Daily Waters Energy on that. I think the part two to your question – obviously very much understand, you know, sort of the additional white space on the map now. I think the short answer to your question is that in the near term and midterm, we are very much aligned with our strategic partner, Flamentera Partners and Brian Sheffield. So on phase one in the pilot, you know, we are aligned for that pilot project and You know, this 160,000 acres that you referenced as part of the Phase 2 development area, you know, part of the deal that we negotiated with Formentera is they will take a percentage of that block, and that creates alignment, and we think that is something that we wanted. I think that alignment creates a lot of opportunity to share learnings. We value learnings. Formentera and Brian's team, and we think that's going to be absolutely critical in our ability to have success in Phase 1 and Phase 2. I think long-term, to your point, I think there will be opportunities to bring more operators into the basin, including Formentera will be one of our competitors long-term. We think that's a good thing because that's going to attract additional wells getting drilled. Service companies will be attracted by the additional delineation And overall, we see costs coming down long-term. So we look at this as a good thing with more operators coming into the basin. And that's really the strategic intent for the checkerboard altogether, is to have opportunity for other operators to drill and compete. And much like what's happened in the U.S., that's resulted in a reduction in well costs through efficiencies, but also more service companies coming into the basin.

Bill, if you don't mind, I've got a third here. Can you talk about why the farm down area is shaped the way it is? From my perspective, it basically has exposure to two different geological settings. Why would that be interesting to a partner?

Yeah, no, it's a good question. I think just to take a step back, you know, the checkerboard was part of a 4 million acre area that we split roughly in 20 blocks. And those 20 blocks were roughly 200,000 acres each. We performed a checkerboard draft much like the NFL draft. So we had areas that we really liked kind of high on our draft board. Probably at the top of that draft board was a phase two development area. And the reason for that, just to give you some colors, because of the quality of the geology, obviously very close. to a de-risk pilot project area. We believe that quality of the acres will extend under this Phase 2 development area. Obviously, very close to existing infrastructure with roads, pipeline 20 miles away, and also very supportive pastoralists and traditional owners in that area. So, this is an area that is development ready, and that's what I'm most excited about, and that's one of the reasons why we prioritized this as part of the checkerboard draft. To your point, beyond 150,000 acres, the northern part extends to a mungy area where there's a number of wells that have gone in. That is a further de-risked part of that 400,000 acres we think will be accretive. Obviously the initial wells that we will look to work with a farm end partner on I think will be closer to the pilot area just because of the de-risked nature and the deeper part of that basin. And so the way I see this happening, much like what's happened in the Wolf Camp and other areas in the U.S., is you start in the deeper sections and work your way, you know, kind of more shallow. And that's why I think this 400,000-acre block will be developed in time. So remember, just within the 160,000 acres in this deep section, we can put up to 1,300 wells. We can develop two to three BCF a day. And that allows us the pathway to deliver the business plan through 2030. So everything else beyond that will be upside.

Got it. Thanks, Joel. I'll turn it over.

Thank you. Our next question comes from a line of Paul Diamond with Citi. Please proceed.

Thank you. Good morning, all. Thanks for taking the call. Just a quick one. Wanted to kind of walk through the pathway on well costs. Talked about, you know, these next few wells expected around $28 million, take out $3.5 for sand. Can you walk me through kind of the rest of the process? Is that just multi-pad drilling, or is there... How should I think about, like, the other low-hanging fruit there?

Yeah, sure. So part of the $28 million is Well testing, obviously in a development scenario, the well testing will come out. One of the other big opportunities that we have by having a multi-well program is that we can implement dipper fracking. So you remember Shenandoah South 2, we were pumping five stages a day. With multiple wells, we think we can pump up to 10 to 12 stages a day. That's kind of what a Marcellus operator is pumping. We believe we can replicate that. So, you know, that's, you know, double the amount of stages that get pumped a day versus, you know, what the well cost, the $28 million well cost is tied to. So there's that combined with the utilization of local sand. And I already mentioned the opportunity for improvements on ROP by, you know, taking learnings from SS2 and SS3. We think the biggest gains will come in the horizontal section. That horizontal section for SS3, for instance, we drilled in 12 1⁄2 days. We've been working very closely with Baker on, you know, having review of the SS3 well. There's a more... there's a better directional tool that we're going to be using for these upcoming wells. We think there's probably two or three days of gains that we can take from there. So, you know, I think it's, I mention the sand because that's really the biggest needle moving opportunity that we have to reduce well cost. These other elements will come from just having more reps. So the more reps you have, Obviously, efficiencies on the pumping more stages of the day, higher rates of ROP coming from more optimized well plan and tools. And I guess just the fourth one is just, you know, just going off one pad, there's no mobilization cost that we're incurring. We have the rig and the crack spread on location. We're going to have a local fan solution hooked up to that. And You know, I think that's what we've been working toward really over the last 12 months is to get into a situation on our pad that has the same look and feel as wells that are being drilled into Marcellus today. That's what we're trying to replicate. And I think we're very, very close to that. We've made a lot of progress in the next 12 months. And what the team needs now is just more reps. So the more reps, I think more efficiencies that we're going to gain And I think, you know, I think what we're trying to, you know, accomplish over the next three wells is, you know, set a trajectory where we can take these next learnings and then show a trajectory to get down to $16 million well cost.

Understood. Appreciate the clarity. And just a quick follow-up on the whole soak period. Okay. So SS1H was 21 days, increased that for the most recent. How should we think about that from a run rate basis? Is that still kind of poking around, seeing where the right level is, or is it the more the better?

Yeah, look, as I mentioned in my opening comments, we did a deep dive study with CoreLab to build a model that we believe will predict kind of the effectiveness of of soaking on production enhancements on a flow test. And, you know, that was a product, you know, of a lot of folks around the table that, you know, come from a lot of experiences in the Marcellus. Obviously, we have some experiences here in the Beetaloo. And recognizing this is the most desiccated rock on the planet. This is a shale target that has been buried for 1.2 billion years old And it's very unique. And we believe that uniqueness in this being a very, very dry shell, how long you soak matters, how you flow back these wells matter. And we've seen, you know, kind of a pretty big kick from 21-day soak on SS1. You know, kind of where our model comes out is that, you know, a 50-day mark is kind of the you know, kind of optimal soaking period to get the best production characteristics out of this highly desiccated shell. So that's what guided the team toward leaving the well shut in 60 days. And, you know, I'm very encouraged by that model that we built. And, you know, it'll put another data point on the board. to help calibrate our model moving forward. But this is, like, very highly valuable information to guide, you know, kind of how we flow back wells in the beetle loop and ultimately how we get the optimal tight curve. That's what we're looking to, you know, get out of this pilot. And part of that is trying to refine our flow back strategy. So hopefully that gives you a little color on the rationale. Understood. Appreciate the clarity. I'll leave it there.

Thank you. Our next question comes from the line of Nish Katia with Quantum. Please proceed.

Hi, Joel. I had three questions, please. First of all, I was wondering, with the 2H well test that's coming up, do you believe that that will give you enough information to sufficiently de-risk the play for farming ease? i.e. so you don't now need to show the performance for a full-length lateral. Secondly, I was just wondering if you'd give a couple of updates on the data center opportunities for Phase 1 and then the MOU with Stantos over the Darwin LNG Train 2. And then finally, this is more of a macro question, Can you talk a bit about the political landscape for gas and LNG in Australia, given the new federal government, how that kind of impacts the future gas strategy initiative, and also with regards to the NT government scrapping its renewables target, presumably in favor of gas? Thank you.

Yes, absolutely. Let me start with your first question on the SF2H well flow test being proposed. you know, kind of the adequate amount of information required for a farm end. I think just to set some context, you know, we have been running a soft process over the last 12 months following the results of the SS1 well. And, you know, we've had multiple IOCs and Asian strategics in a data room for the last 12 months. You know, we've provided those counterparties a deep dive around the subsurface, obviously the SS1 well, you know, well performance, and also kind of all the key advancements we've made around reducing costs with the H&P rig and Liberty Fract Spread. We've always believed that, you know, the pilot wells, as they get drilled and completed and further de-risking occurs, that will be the opportune time to have a farm-down discussion with an IRP counterparty. And this is what's led us to appoint RBC as our advisor on the farm-out. Remember, RBC was the bank that ran the original farm-out process for Origin Energy, in which we successfully won that bid. So they have a lot of intrinsic knowledge on the Beetaloo. They have a lot of intrinsic knowledge on the players that are interested in the Beetaloo. And, you know, all those players we've spoken to, and I think SS2, I think, will be a big step forward around another de-risking point that will provide additional comfort on the extension from 500 meters to 1,700 meters on a horizontal extension. Being able to replicate that performance of what we saw in SS1 I think has been very, very important. Being able to demonstrate kind of the productivity that comes from a modern U.S.-style track with our Liberty Energy track equipment, I think it's very important. And then all the cost efficiencies that I've spoken previously about, I think are very, very important. So, you know, we will find out, you know, after we get around the table in the months and quarters ahead around, you know, kind of how the process is, you know, kind of concludes. I'm kind of in a position of a lot of confidence because I think we are having, showing a lot of good progress. I think we're sniffing and de-risking this part of the basin. And in the backdrop of all this is a structural short gas market in which molecules need to come online to feed into up to a BCF a day of shortfall on the East Coast. So these are all things that I think give us confidence around our ability to attract a high quality partner in the farm down process. Time will tell around if this is the adequate amount of information required to get a very strong farm out deal done. But right now, as I said today, looking at a lot of the progress we've made and also 12 months of discussions we've had with a lot of counterparties, I believe, I'm operating with high confidence that we will be successful in the process. I think the second question you had was related to data center opportunities. We continue... to have discussions with a number of parties on our data center strategy. I think just to take a step back, we believe data centers in the Northern Territory are well positioned for being powered with gas when the beetle is, simply because we have an abundance of gas supply coming online. You know, we have You know, I would say none of the issues that a lot of operators in the U.S. struggle with around not in my backyard. We don't have any of that going on in the Northern Territory. In addition, you know, there is opportunities to feed into an existing fiber network that is 20 miles away from our pads. And so I will hope in the quarters ahead we will have a few MOUs to provide the market a little bit more color and definition around this data center strategy. I see this being part of an expanded phase one opportunity that, you know, we would look to build upon the $40 million a day that we're delivering in the middle of next year. Just to give you a sense of the scale, we need about another $200 million a day to deliver a gigawatt data center. That could be a nice goal for an expanded Phase 1 in 2027-28. The final question you had is just around the macro environment and political situation both at the federal level and the local level in Australia. I think You'll know that we had an election that occurred on May 3rd in Australia. The government, the labor government that we've been working with over the last three years stayed in power. So I look at this as being kind of a status quo and slightly accretive because the federal labor party now has a majority, a very strong majority on the federal side. That's a positive. And, you know, we have developed very deep relationships with the federal government and all the key ministers, and we will look to build on that foundation in the next three years into the next election. So I'm feeling very positive about the outcome. I think on the local side, the Northern Territory government, you know, came into power about eight months ago. This is a country-level party that now is in power. That is the right side of right-of-center politics in the Northern Territory. They also have a very strong majority, and we have a lot of depth in the relationships that we've built. In the last 12 years, I've been in this job locally. So, you know, I think the fact that they have rescinded their net zero policy Policy, I think, is really not relevant to our ability to be working with this local government around permits and approvals for our phase one and phase two and ultimately phase three of our development. I look at it as a real win that the new local government, once they came into power, they appointed a territory coordinator. This territory coordinator was put in place to facilitate accelerated approvals. I think that's going to be very helpful as we move forward in these bigger developments to have the opportunity to have someone in place that reports directly to the chief minister that can facilitate accelerated approvals. That's something that we've been discussing with local government for many years. You know, I really applaud the local Northern Territory government on that to take that step and, you know, put in place a way for us to facilitate accelerated approvals.

I appreciate those insights, Joe.

Thank you. There are no further questions at this time. I'd like to turn the call back over to management for closing remarks.

Thank you very much. First, I'd like to just thank everyone for joining, especially our existing and new shareholders that supported our capital raise. And we look forward to delivering flow test results on Shenandoah South 2H in about 30 days. And again, a IP90 that we're working toward in August. Thank you for your time, and we look forward to keeping everyone updated on Tambor and resources in the future.

Thank you.

This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.