Tamboran Resources Corporation

Welcome to Tamborine Resources second quarter fiscal year 2025 earnings release conference call. 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, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce Joe Riddle, Chief Executive Officer. Thank you, sir. You may begin.

Thank you and welcome to Tamborin Resources second quarter fiscal year 2025 result presentation. My name is Joe Riddle, Chief Executive Officer for Tamborin Resources. And joining with me this morning is Eric Dyer, Chief Financial Officer. Before we get into the materials, I'd like to refer everyone to the disclaimer. on slide two associated with forward-looking statements. Moving to slide three and the highlights of the last quarter. First, the company successfully drilled and cased the SS3 well. This well included a full 10,000-foot horizontal section and drilled at a Bigaloo Basin record 840 feet per day. Two, we completed the SS2H well. Over 35 frac stages were pumped. and we delivered a record profit intensity over those 35 stages. The company will be targeting an IP30 flow test in April of this year, and following the 30-day flow test from SS2, we will be moving to SS3 to finish completion operations and target an IP30 flow test for SS3 in June of this year. The company continues to make progress toward a final investment decision for the Shenandoah South pilot development project. Over the quarter, we entered into binding agreements with the APA group to support the build and construction of a 12-inch pipeline connecting the SS pilot to the local 12-inch pipeline to move gas from our pilot project to the local Northern Territory gas market where we'll be producing 40 million cubic feet a day over the next 15 years. First guess from this project remains on track to start in first half of 2026. Over the quarter, the company continues to make good progress around business development opportunities, including the progression of a data center strategy that we would envision being part of an expansion to our phase one development. I will talk more detail around this later in the presentation. And finally, the company signed a non-binding MOU with the ASX listed E&P company Zantos around progressing technical studies associated with the expansion to the Darwin LNG project. The company ended the quarter with a cash balance of $59.4 million. This is following receipt of a R&D grant of $6.2 million. And the company remains fully funded to deliver IP30 flow tests from SS2 and SS3 through the end of June of this year. Moving to slide four, in more detail around the progression of our Shenandoah South pilot development, you can see by the map in the middle of the page, the company remains very focused around the million acre development area that's highlighted in the structure map on the left in yellow. As you zoom down into the middle of that million-acre development area is our six-well pad where we've now drilled two horizontal wells. These are the first two of six wells that we anticipate to develop our 40 million cubic feet a day for this pilot development. You can see by the picture on the right, this is a snapshot of the new Liberty equipment that is currently on site and has been progressing the completion of our SS2 and SS3 wells. Again, over the quarter, the company successfully drilled the FS3H well to 21,169 feet, and we completed this drilling in 25 days. Again, that represents over 840 feet per day that was achieved on drilling performance and remains the fastest well that has been drilled in the Beeloo Basin to date. We geosteered the full 10,000-foot horizontal section within a 65-foot radius, target, and what we saw within that 10,000 foot horizontal well was a high quality contiguous middle bacteria deshell, and most importantly, no faulting. The company commits simulation operations on FS2 and FS3 in January of this year. On FS2, we completed 35 track stages across the 5,500 foot horizontal section. and achieved BLE-based in records for average profit intensity across those 35 stages. On FS3, the company took precautionary and proactive steps to pause completion operations based on a detection of stress and a case in connection. Remediation activities on FS3 are ongoing, and we are targeting a continuation of the simulation program in second quarter of this year. Overall, we'll be targeting IP30 flow rates from SS2 in April of this year and an IP30 from the SS3 well in June of this year, subject to weather conditions. Moving to slide five, the company continues to make significant improvements in drilling performance from our last well that we drilled over the quarter in SS3. This well was drilled in 25 days. At an average speed of 843 feet per day, that represents 43% faster than the SS2H well. In reference to the table on the bottom part of the slide, you can see the increases in performance we've made in SS3, primarily driven by the section of the top holds and the rope section, where historically it's taken between 10 and 11 days to drill that section. Now in SS3, We drilled that section in less than five days. And in the horizontal section where it took 17 days to drill in SS2, we were able to drill in 12 and a half days. The total drilling cost for SS3 is approximately $10 million, and the company has identified significant cost savings that will drive further reductions and increase drilling performance in our follow-on pilot development wells being drilled in the second half of this year. to slide six one of the most encouraging elements of our two well drilling program this year has been the consistency in the geology that we've seen in our two wells ss2 and ss3 as it compares to the ss1 pilot hole that is roughly three miles south from these two horizontal wells we've seen very consistent quality and a very gentle undulating structure across the full horizontal section with no faulting observed. In addition, we see very strong gassos across both horizontal sections, which we believe will translate into very good productivity in our well test in both wells. Moving to slide seven, the summary of the simulation campaign from SS2 and SS3. On our SS2 well, we completed 35 stages with our new Liberty equipment that's currently on site. This was done over a 5,500-foot section, and we were pumping a profit intensity of approximately 2,700 pounds per foot. This represents a 26% higher profit intensity that we pumped at SS1H. And most encouragingly, the 18 of the 35 stages, we successfully executed the full Tamborin V2 design of pumping greater than 2,800 pounds per foot and pumping in at 90 to 100 barrels a minute. We're also able to achieve five stages a day for the single well operation on multiple days. And this is in line with U.S. operational efficiencies. We're currently cleaning up the SS2H well. ahead of commencing a IP30 that will have a result to report to market in April of this year. On the SS3, while we took proactive and precautionary steps to undertake a remediation of a stress and a casing connection that was observed, we anticipate this remediation to be resolved in the next 30 days ahead of recommencement of simulation activities in second quarter of this year. We see this as an opportunity to incorporate lessons from the SS2H well to increase efficiencies and place a higher profit intensity across the 60 stages that we plan to pump in SS3. We'll be targeting an SS3 IP30 flow test result in June of this year. Moving to slide eight and a summary of the completion designs between Senadilla South 1H, Senadilla South 2H and Senadilla South 3H. As you can see we've had the opportunity to apply learnings from the SS1H well into our recent SS2H well that we're calling our Camborne V2 design. This is a design where we pumped 35 stages at a little over 2,700 pounds per foot and we pumped 90 to 100 barrels a minute. We are anticipating targeting IP30 flow test results of greater than 10.7 million cubic feet a day. Again, we are targeting this IP30 flow rate by April of this year. We will have the opportunity to apply learnings from this SS2 H well into our SS3 H well, and where we will have the opportunity to optimize the Tamborin V2 design where we anticipate pumping 60 stages at greater than 2,800 pounds per foot and greater than 100 barrels a minute. We are planning to target IP30 flow rates of greater than 19 million cubic feet a day for the Shenandoah South 3H well test that we anticipate in June. Moving to slide nine, we remain on track for delivering our SS pilot project by first half of 2026. The results of our two wells, Shenandoah South 2H and Shenandoah South 3H will guide the number of wells that we will follow up and drill later this year that will deliver into a binding gas sales agreement of 40 million a day for 15 and a half years with the Northern Territory Government. Over the quarter, we signed binding agreements with APA Group to deliver a 12 inch type line that will connect the pilot project to the local Northern Territory Pipeline called the Amadeus Gas Pipeline that will deliver this 40 million cubic feet a day to the local Northern Territory gas market. We also commenced procurement of the 40 million a day facility. We'll be finalizing approvals for our Schindler and Dillis South pilot project in the next few months ahead of a final investment decision that we'll look to take in mid 2025. Again, our project remains on track to deliver first gas of 40 million cubic feet a day in first half of 2026. Moving to slide 10, as I mentioned in my opening comments, the company is looking at an opportunity to expand our phase one development to include additional gas supply that could feed into a data center strategy. You can see by the map on the left, Australia is becoming a major data center hub. Over 200 data centers are currently in Australia, and we believe the Northern Territory has the opportunity to be a growth area for new data centers. Given the existing fiber optic cables that connect the Northern Territory within other areas of Australia, but most importantly into Asia-Pacific, these fiber optic cables run about 30 miles from our Shenandoah South pilot project, and we believe that this creates an opportunity to match gas from the Beetlewood Basin to feed into energy for new data centers being constructed in the Northern Territory. We have commenced commercial discussions with potential partners to develop multiple data centers in the Northern Territory, and we will be updating the market further as we continue to make progress on this strategy. Moving to slide 11, over the core, we also executed a non-binding MOU with Santos to evaluate an expansion to the existing Darwin LNG plant that Santos operates. This non-binding MOU will consider technical studies to look at developing new supply from our jointly held EP161 permit and connecting that to the Darwin LNG expansion where we anticipate up to 6 million tons of new LNG capacity being built at Darwin LNG via brownfield expansion. We believe this creates a really great opportunity to potentially integrate this Darwin LNG expansion with our phase three NTLNG development. Moving to slide 12, the company ended the quarter with a cash position of $59.4 million. That includes $6.2 million that the company received via an R&D credit over the quarter. The company remains fully funded to deliver IP30 flow rates for our SS2 and SS3 wells. In addition, Tamborin is evaluating a range of options to fund the remaining wells and our SS pilot development. and also associated infrastructure. In addition, the company continues to explore potential farm out opportunities to accelerate our phase two and phase three developments. These farm out opportunities could include the drilling of additional wells to support reserve maturation to underpin infrastructure tied to phase two and phase three of our business plan. Moving to slide 13, you can see the upcoming catalyst. starting in March where we'll commence the flow testing of our SS2 H well and target an announcement on our IP30 from this SS2 well in April. Following the well test of SS2, we'll move to stimulate and flow test our SS3 well and target an announcement on our IP30 flow test from SS3 in June. In mid-2025, we'll look to take a final investment decision under SS pilot program that will again target first gaps from this pilot project in first half of 2026. Thanks very much and I'll turn the call back over to the operator for our question and answer session. Thank you.

Thank you. If you would like to ask a question, please press star 1 on your telephone keypad. A 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. and for participants using speaker equipment, it may be necessary to pick up your handset before pressing the start keys. One moment while we poll for questions. Our first question is from Kalei Akamine with Bank of America. Please proceed.

Hey, good morning, guys. This is Joel, Eric. I guess first off, between the pipeline lateral, the pilot, the MOU, the data center news, you guys have been really busy and we like to see it. My first question is on the upcoming flow test, and maybe this is two parts. So first part, can you remind us why there's a gap between the completion and the flow test? And second, can you remind us what the normalized flow test was for SS1? And I guess what I'm driving at is when you think of your target for SS3 at 19 million cubic feet per day, to us it seems a touch conservative.

Thanks very much for your question, Khalil.

First, on the initial question on the time window between completing the simulation on SS2 and SS2 flow tests, we are, again, in the process of cleaning up the well. We're going to be running our two and seven eighths tubing, and we're going to be unloading the well in the next few weeks. And once we get gas breakthrough, we will start our IEP3 in early March. That also includes a 10-day silk period, and that silk period is due to learnings that we picked up from SS1, which is associated with having an extended shut-in to allow our completion to continue to induce superhighways within the shale. That's due to the highly desiccated mid-doctrine shale that we've pumped our completion into. And so that extra 10 days has shown to have direct benefit from our SS1 well. So that's the extra time that we're taking to fully initiate our IP30 flow test. As far as the conservatism that's built in, you're exactly right. If you extrapolate The productivity that we saw in SS1 was a full 10,000 foot of the horizontal in SS3. That's roughly about 19 million cubic feet a day. So that's really what we're guiding towards. Obviously, as we have higher stimulated rock volume, there's increased profit intensity that we've been pumping for SS2 and expect to continue to pump in SS3.

We have the potential to see higher rates than that.

Got it. I appreciate that, Keller. The second question is on the Santos MOV. So our understanding is that Santos has a position in EP161 where you guys are the minority partner, and that's different than where your pilot activity is concentrated in EP98. So my question is on the scope of the study. Are they trying to de-risk EP161? before they move forward, or is de-risking your position in EP98 sufficient to move forward with ELLU?

Yeah, so really good question. We see the rocks between EP161 and the pilot area on EP98 being very similar in the deepest part of the basin. They've got two deficit centers, one on the east, where the 161 block is focused, and then the second, it got the centers on the left part of the basin. And so we have data from the last horizontal wells that had been drilled on EP161 in 2021, in which we flow tested greater than nine days on both of those wells. really that information guided us toward the SS1 simulation that we pumped last year. So we see a lot of symmetry between what we're doing on SS pilot program and the number of pilot wells that we're drilling this year being very similar to techniques that we would be working with our partners to hand toss on on EP161. So in a lot of ways, we're able to de-risk the EP161 opportunity to what we're doing on EP98. This is part of cracking the code on the completion design. So, as far as the TLNG expansion that we're working with SAMCOPS, I think we're also keeping an open mind on where gas could be sourced to supply that expansion train. And that will be part of the study that we finish with Santa Claus over the course of this year.

So, what's the path forward for D-161? What wells do they have planned?

So, we have an opportunity to drill additional horizontal wells in 2026. We're currently discussing two horizontal wells that will be drilled on EP161 during 2026. And we hope to finalize that work program over the course of this year, hopefully by mid-year.

Great. I appreciate that.

I think the one thing I want to reinforce is that, you know, I think it's important that we bring along our partners early. so that when we think about a northern pipeline connecting the Beagle Loop to Darwin, we do that in collaboration with all of our operators in the Beagle Loop. And that's part of really the push by Tim Boren to include Santos as part of developing LNG expansion.

And obviously, as we look at NTLNG, we see a lot of potential to integrate. That's great. Thank you.

Our next question is from Scott Arnold with RBC Capital Markets. Please proceed.

Yeah, thanks. I was wondering if you could provide a little bit of color on some of the detection of stress in the casing that you encountered and just a little color behind that. Was it mechanical versus reservoir related? And, you know, based on your conversations with your service providers, Is that something that they've encountered elsewhere, or is it more, you know, a dynamic of learning to be the loop?

Yeah, great question, Scott. This is a mechanical issue that the company identified as we were coming out of a hole in the vertical section on the fifth stage on SS3. We detected a stress anomaly and we ran back in after we paused the simulation operation with an acoustic tool and a camera to get some better information about what the stress anomaly was. And out of abundant precaution, what we decided to do is reinforce that section and in parallel continue the simulation on SS2. and move forward with the well test on SS2. We expect, after we finish the well test on SS2, to move back on SS3 and pump the remaining 50 stages on SS3 and get a flow test in June. That's the plan. Now, what that provides is an opportunity to take the learnings from SS2, both on the completion side and what we see on the flow test, and deploy those burnings into the 60 stages we want to pump on SS3. The thing I want to underscore is this has nothing to do with the reservoir. This is all due to the mechanical. This kind of issue happens every day of the week in the Permian, Marcellus, Eagleford in the U.S. You know, the service providers that have been advising the company on this have a lot of experience, have a lot of knowledge. Um, and we don't believe this is, um, you know, this is an issue with high confidence that we could resolve. Again, we have a sharp eye on safety. We have a sharp eye on attention to detail. Um, and so when we saw this slight anomaly, we, you know, we focused on identifying where this was coming from in the vertical fraction and then look to remediate. Um, so that should give you a little bit of color.

Okay. No, I appreciate that color. And, and, uh, I guess my follow-up question is just on the, you know, stimulations in general. I know you've, you know, again, you know, maybe gone, you know, a little bit stronger on the frack than initially thought and maybe backed off on the final decision. But can you discuss, you know, some of the rationales of, you know, the variation between, you know, some of the original plans and how you're going to frack this? Is it, you know, is it – you know, service availability? Is it timing? Is it, you know, what you think the reservoir, you know, can take? You know, just give us a little color around, you know, how you dialed into that number and why it's kind of moving back and forth a little bit.

Yeah, sure. Great question, Scott. So we went in with a, what we're calling Panborn V2 design where we were looking to target simulation intensity of 2,800 pounds per foot pumping in at up to 100 barrels a minute And we tightened up the spacing on our design when we had a shorter bottle on SS2. So we took the opportunity to tighten up the spacings from what we saw in SS1, which is about 165 feet to 130 feet. Once we started pumping in that 130-foot spacing per stage, what we saw was stress shadowing. And we were having a little bit of trouble placing all the profits. And so we optimized that completion all, you know, kind of real time. And so we made the decision to go back to 165 foot spacing on our stages. And, you know, I was really pleased to see the placement of all the profits we were pumping. We were, you know, we ended up placing about a half a million pounds per stage. We were able to see, you know, kind of the 2,800 pounds per foot once we opened up the spacing a little bit. And, you know, pumping in 100 barrels a minute. I think what gave me the most encouragement is the last 15 or so stages, we were consistently pumping about 2,800 pounds per foot. Last 10 stages, we pumped right at about 4,000 pounds per foot. and up to 110 barrels a minute. So what that has really shown us is some learning around, you know, kind of the right stage spacing so that we don't get into the stress shadowing between the stages. But, again, one of the learnings that, you know, the Marsalis operators went through early on is how do we get our stage spacing right. You know, within the SS2 well, we were able – have real-time learning to really optimize this completion design. I'm feeling very good about kind of the next 50 stages for SS3, having, you know, taking this learning forward.

Got it. I appreciate that, Collar. Thank you.

Our next question is from Charles Mead with Johnson Race. Please proceed.

Good morning, Joel and Eric and anyone else on the Tamborin team there. Joel, I want to pick up on Scott's line of questioning. And I think the graph you put on the lower right corner of slide seven really does a great job, I think, telling at least part of that story, showing that you've got – once you made that – once you made that adjustment that you really just ripped off the stages and really put away the sand after that, I want to ask, you talked about stress ironing between the stages. Does that suggest to you that you've got maybe a slightly more permeable rock there than, let's say, the typical U.S. onshore conventional, and so that's what calls for the bigger stages, and And did you add perfs to be able to put away all that sand when you like those stages?

So first of all, yeah, we did add some perfs.

That's part of the increase in the stage spacing. We did include additional perfs. And I think there's a lot of things that go into how you put these stages away. But I think one element of why we're able to put away as much sand is due to the quality of the rock. So, higher ferocity, you know, and some higher permeability are two elements of that. One of the things we're really excited about, again, you know, part of our analog that we've always talked about is how the Beetaloo shell looks very similar to the Marcellus. And so, You know, we have designed our completions to align with what is working in the Marcellus. That's where we started in SS1. But what we're finding is the more stages that we pump, you know, the Beetle will have its own signature. And, you know, the opportunity to dial in on the completion design real time is due to, you know, kind of the pressure regime that we see here, 0.6 PSI per foot. It's due to the porosity, the permeability, you know, being slightly better than even you see in the Marschella. So this is all kind of moving in a positive direction, I would say, both from validation of the completion design with the quality of the rock that we see, but also the being able to zero in on what is the best completion for the beetle loop, not just modeling all the Marcellus, but really, this is why we call this a B2 design. This is very specific toward the beetle loop, and I'm highly encouraged that we're able to do this so early on in the program. If you remember in the Marcellus, it took hundreds of wells to really perfect this kind of design, and we recognize we have a much shorter window to get down the curve. And the team's doing a great job. Barron and the ops team down in the field working side-by-side with Liberty. We're doing real-time modeling as we pump every stage. And this is what 21st century modern field looks like, is that as you're pumping stages, you're getting real information, real data, and you're making optimizations, between the stages. You're not waiting to pump the whole stage across the whole horizontal before you adjust your design. You're doing it real time. So I'm incredibly positive about the reception that the rock is receiving based on its design, and it gives me a lot of encouragement as we think about SS3. Got it. And one just quick hitter for me on that, and then a bigger question. On page six, you have on your lateral graph, you're showing It says total gas, average temperature. Is that gas still porosity? Is that the way to interpret that? That's correct. Okay. And then the bigger question, Joel, you made a mention out of – here's the setup. I'd like to ask you to give us a little bit of an update on your view of the domestic Australian natural gas market because – You know, it's a little obscured, I think most of us on this call. And perhaps wrapping into that answer, you made mention of, you know, farming out to maybe in the back half of the year to get the next four wells in the Shenandoah South Project. It seems to me from where I sit that you guys are getting more attention from the domestic players, both EMPs, but also consumers. But maybe that's not the case. Maybe you could just elaborate on what you're seeing domestically there. Yeah. First of all, the domestic demand on the east coast of Australia is about one and a half BCF a day. That's held flat now for many decades. We don't anticipate that demand being reduced anytime soon. But to your point, you know, we... seeing moratoriums in New South Wales and Victoria. No new exploration really to be heard of on the East Coast. And a major producer in the domestic market has been the fast trade field that's operated by Exxon. That's a field in terminal decline. So when we look out three to five years from now, we see a shortfall of greater than a BCF a day emerging. That's based on government numbers. The government regulator puts out a report, and that's been very consistent in that 28 to 30 time period when you start to see significant shortfalls. And so what we're trying to do is get out in front of that. You know, we think a pipeline from the Betelgeuse to the East Coast to Baxville, this domestic market, will be key. We know that LNG import terminals are being discussed among, you know, various data suppliers as a solution. We think that is not – we think the pipeline from the Betelgeuse is a much better solution. for the Australian consumer, given that, you know, there's a potential for lower-cost staff moving into the market versus importing LNG from outside of Australia, in addition to lower emissions. So, you know, here in Australia, we're very focused on reducing costs to the consumer. We're very focused on reducing carbon emissions. And the Beetleland Pipeline, you know, you know, that will target as early as 2028, check both of those boxes. And just to give you a little bit of color, you know, the import LNG represents about five times the amount of carbon emissions versus the pipeline from the Betaloo. So if you want to reduce carbon emissions here in Australia, you know, having a big pipeline from the Betaloo to the East Coast is the solution.

Our next question is from Jeff Grant with Alliance Global Partners.

Please proceed.

Hi, Joel. I'm curious to touch on the prior question regarding kind of IP rates, expectations, or benchmarks, if you will. So it looks like we're just kind of extrapolating results from the 1H, but given the larger frack that you guys have put away and plan to continue putting away, I'm curious how you guys are thinking about analyzing the value of those larger fracts to kind of inform subsequent developments and continue to optimize things.

Yeah, look, we're going to wait and see on the IP30.

One of the things that as a reservoir engineer with that background, I'm very interested to not just see the IP30, but what these flow rigs look like over 12 months. That's really where The purpose of the pilot is to see well tests that, you know, go beyond 30 days. I think 30-day IP will give us an indicative view of the uplift that we potentially could see with increased profit intensity versus FS1. I think that's a data point I'm looking for. But from there, you know, I think as we move forward through the course of the year, you know, The information from the IP3 will guide how many wells we think we need to deliver that $40 million a day in our pilot. And then, you know, we'll start to get zeroed in on what productivity out of this part of the deal looks like. And then that will allow us to plan for much bigger development as we work that longer duration flow test coming out of these wells. It'll give our team a lot more comfort around the potential to book reserves and to start looking at a much bigger wealth plan.

Great. That's really helpful.

For my follow-up, I apologize if I missed this. I don't think it's been covered. But local SAMs, any updates on potential sourcing options there? I know that was obviously a big question. potential line item from a well-cost savings perspective. So just curious to get any updates on recent conversations or progress there.

Yeah, look, we'll continue to make progress on the local sand solution.

We have a wash plant that we're planning to source and get out in the field later this year and hopefully be able to use that same washing plant for these follow-up pilot wells is the target. In parallel with that, we are progressing approvals at the Northern Territory level to get a full-scale sand mine approved and kind of positioned for that sand mine to be operational in 2026. So permitting is progressing. We're also talking to a few potential partners that we could work with on constructing that local sand line.

And we're going to be updating the market further as we may continue to make progress on that.

Our next question is from Anish Kalida with Hammond and Partners.

Please proceed.

Hi. So the first question is just looking at the first half of this calendar year, what's the expected net capex to finish off the wells? And then kind of going forward, what's your current thinking in terms of best case for financing options and timing of that financing for the phase one development? I see that you're still mentioning farm-out discussions as well. Just wondering if those are somewhat on hold, waiting for the results of 2H and 3H, or actually picking up given, I suppose, the positives you're seeing around global energy markets at the moment.

Yeah, really good question, indeed. The cost that we have in front of us are two wealth tests, 30 days each, Each of the wealth assets is roughly about $2.5 to $3 million net to the company. And in addition, there's around $10 to $12 million U.S. of completion costs still remain as part of the SS3 wealth. So those are the immediate costs that are coming at us to deliver the IP30 flow rates for both of our results. And I want to stress The information from those two wells will guide how many wells we need in second half of this year to drill to deliver our 40 million cubic feet a day contract. Right now, we've been conservative in assuming four wells that are going to be required, but we have the opportunity to potentially drill and complete less wells to deliver that 40 million a day. The capital associated with the drilling will be determined, you know, in the next few months based on what we see from the well test. We're looking at a range of debt facilities to support the financing that the infrastructure applied to the pilot. We're making good progress on that and anticipating the months ahead to have that financing finalized. remember that the GATT-DELS agreement that we signed with the NT government is a fixed-price CPI-linked contract, which gives our opportunity to attract a good portion of the capex that are required for the pilot. We could force that for debt. That's why we continue to remain focused with various debt providers on that. I will say on the farmhouse, We are entertaining a number of discussions with potential partners, and we'll continue to progress that through the year of 2025.

Thanks.

And just with some of the thoughts that you've had, in terms of drilling time and expecting to improve that and kind of what you've seen so far on the completion costs plus the sand. Any kind of updated thoughts on what the development wells will cost going forward or kind of any updated target from where you think you can kind of get to for drilling and completing these wells?

Yeah, sure.

Great question.

If you look at the two wells, you know, we are drilling at around $10 million per well, just the drilling alone. And based on the FS2 35 stages that we pumped, that's approximately about $15 million U.S. So all in drilling incomplete is about $25 million is where we sit today. As we move forward with the follow-up pilot wells, We will, again, be looking to integrate the local sand solution. That will be a material cost reduction in the completion size of around $4 million that we see on the sand. We also see additional cost savings from bulk ordering equipment. That includes steel, cement, and that is cost savings that we see as we get into a continuous drilling program. In addition, on the completion side, there is an opportunity to employ zip refracts that allow us to achieve, you know, pumping eight to ten stages a day. You know, we were pumping five stages a day on FS2 at the single well. As we start drilling and completing multiple wells, zip refracts, I think, will allow us to double the efficiencies. on pumping the number of stages a day.

Obviously, it's going to translate to cost savings.

So, you know, I just want to underscore that the company remains very, very sharply focused on how do we reduce cost as we get into a development. We think there's a pathway to reduce cost to around $15 million total for BNC. That is our target. That's our goal.

And I believe based on the last couple of wells that we drilled here on the pilot, we're on track.

We have reached the end of our question and answer session. I would like to turn the conference back over to Joel for closing remarks.

Well, thank you very much.

And I appreciate all the comments and questions. And I look forward to a very exciting few months ahead for the company. And I look forward to updating everyone for their next quarter.

thank you very much thank you this will conclude today's conference you may disconnect your lines at this time and thank you for your participation