Greetings. Welcome to Tamboran 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 Joel Riddle, Chief Executive Officer. Thank you, sir. You may begin. Thank you and welcome to Tamboran Resources' second quarter fiscal year 2025 result presentation. My name is Joel Riddle, Chief Executive Officer for Tamboran 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 SS-3 well. This well included a full 10,000 ft horizontal section and drilled at a Beetaloo Basin record 840 ft per day. Two, we completed the SS-2H well. Over 35 frac stages were pumped, and we delivered a record proppant intensity over those 35 stages. The company will be targeting an IP30 flow test in April of this year. Following the 30-day flow test from SS-2, we will be moving to SS-3 to finish completion operations and target an IP30 flow test for SS-3 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 in pipeline connecting the SS pilot to the local 12 in pipeline to move gas from our pilot project to the local Northern Territory gas market, where we'll be producing 40 million cu ft a day over the next 15 years. First gas from this project remains on track to start in the 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 1 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, Santos, around progressing technical studies associated with the expansion to the Darwin LNG project. The company entered the quarter with a cash balance of $59.4 million. This is following receipt of an R&D grant of $6.2 million. And the company remains fully funded to deliver IP30 flow tests from SS-2 and SS-3 through the end of June of this year. Moving to slide four and 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 cu ft 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 SS-2 and SS-3 wells. Again, over the quarter, the company successfully drilled the SS-3H well to 21,169 ft, and we completed this drilling in 25 days. Again, that represents over 840 ft per day that was achieved on drilling performance and remains the fastest well that has been drilled in the Beetaloo Basin to date. We geo-steered the full 10,000 ft horizontal section within a 65 ft target, and what we saw within that 10,000 ft horizontal well was a high-quality contiguous Mid Velkerri B Shale and, most importantly, no faulting. The company commenced stimulation operations on SS-2 and SS-3 in January of this year. On SS-2, we completed 35 frac stages across a 5,500 ft horizontal section and achieved Beetaloo Basin records for average proppant intensity across those 35 stages. On SS-3, the company took precautionary and proactive steps to pause completion operations based on a detection of stress shadowing and a casing connection. Remediation activities on SS-3 are ongoing, and we are targeting a continuation of the stimulation program in the second quarter of this year. Overall, we'll be targeting IP30 flow rates from SS-2 in April of this year and an IP30 from the SS-3 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 SS-3. This well was drilled in 25 days at an average speed of 843 ft per day. That represents 43% faster than the SS-2H well. In reference to the table on the bottom part of the slide, you can see the increases in performance we've made in SS-3, primarily driven by the section of the top hole to the Moroak section, where historically it's taken between 10 and 11 days to drill that section. Now, in SS-3, we drilled that section in less than five days. And in the horizontal section, where it took 17 days to drill in SS-2, we were able to drill in 12 and a half days. The total drilling cost for SS-3 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. Moving 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, SS-2 and SS-3, as it compares to the SS-1 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 gas shows across both horizontal sections, which we believe will translate into very good productivity in our well test in both wells. Moving to slide seven as a summary of the stimulation campaign from SS-2 and SS-3. On our SS-2 well, we completed 35 stages with our new Liberty equipment that's currently on site. This was done over a 5,500 ft section, and we were pumping a proppant intensity of approximately 2,700 lbs per ft. This represents a 26% higher proppant intensity than we pumped at SS-1H. And most encouragingly, in 18 of the 35 stages, we successfully executed the full Tamboran V2 design of pumping greater than 2,800 lbs per ft and pumping in at 90 bbl-1 00 bbl a minute. We were 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 SS-2H well ahead of commencing an IP30 that will have a result to report to market in April of this year. On the SS-3 well, we took proactive and precautionary steps to undertake a remediation of stress shadowing and a casing connection that was observed. We anticipate this remediation to be resolved in the next 30 days ahead of recommencement of stimulation activities in the second quarter of this year. We see this as an opportunity to incorporate lessons from the SS-2H well to increase efficiencies and place a higher proppant intensity across the 60 stages that we plan to pump in SS-3. We'll be targeting an SS-3 IP30 flow test result in June of this year. Moving to slide eight and a summary of the completion designs between Shenandoah South 1H, Shenandoah South 2H, and Shenandoah South 3H. As you can see, we've had the opportunity to apply learnings from the SS-1H well into our recent SS-2H well that we're calling our Tamboran V2 design. This is a design where we pumped 35 stages at a little over 2,700 lbs per ft, and we pumped 90 bbl-100 bbl a minute. We are anticipating targeting IP30 flow test results of greater than 10.7 million cu ft 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 SS-2H well into our SS-3H well, and we will have the opportunity to optimize this Tamboran V2 design, where we anticipate pumping 60 stages at greater than 2,800 lbs per ft and greater than 100 bbl a minute. We are planning to target IP30 flow rates of greater than 19 million cu ft 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 the 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 the APA Group to deliver a 12 in pipeline that will connect the pilot project to the local Northern Territory pipeline called the Amadeus Gas Pipeline that will deliver this 40 million cu ft 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 Shenandoah 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 cu ft a day in the 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 1 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 mi from our Shenandoah South Pilot project, and we believe that this creates an opportunity to match gas from the Beetaloo 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 quarter, 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 EP 161 permit and connecting that to the Darwin LNG expansion, where we anticipate up to six 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 3 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 SS-2 and SS-3 wells. In addition, Tamboran is evaluating a range of options to fund the remaining wells in our SS pilot development and also associated infrastructure. In addition, the company continues to explore potential farm-out opportunities to accelerate our Phase 2 and Phase 3 developments. These farm-out opportunities could include the drilling of additional wells to support reserve maturation to underpin infrastructure tied to Phase 2 and Phase 3 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 SS-2H well and target an announcement on our IP30 from this SS-2 well in April. Following the well test of SS-2, we'll move to stimulate and flow test our SS-3 well and target an announcement on our IP30 flow test from SS-3 in June. In mid-2025, we'll look to take a final investment decision on our SS pilot program that will again target first gas from this pilot project in the 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 one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two 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 star keys. One moment while we pull for questions. Our first question is from Kalei Akamine with Bank of America. Please proceed. Hey, good morning, guys. It's 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 SS-1? And I guess what I'm driving at is when you think of your target for SS-3 at 19 million cu ft per day, to us, it seems a touch conservative. Thanks very much for your question, Kalei. First, on the initial question on the time window between completing the stimulation on SS-2 and the SS-2 flow test, we are again in the process of cleaning up the well. We're going to be running in our 2 7/8 in tubing, and we're going to be unloading the well in the next few weeks. Once we get gas breakthrough, we will start our IP30 in early March. That also includes a 10-day soak period, and that soak period is due to learnings that we picked up from SS-1, which is associated with having extended shut-in to allow our completion to continue to induce superhighways within the shale. That's due to the highly desiccated Mid Velkerri B Shale that we've pumped our completion into. That extra 10 days has shown to have direct benefit from our SS-1 well. So that's the extra time that we're taking before we 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 SS-1 over the full 10,000 ft horizontal in SS-3 at roughly about 19 million cu ft a day, so that's really what we're guiding toward. Obviously, as we have higher stimulated rock volume through increased proppant intensity that we've been pumping for SS-2 and expect to continue to pump in SS-3, we have the potential to see higher rates than that. Got it. I appreciate that color. The second question is on the Santos MOU. So our understanding is that Santos has a position in EP 161 where you guys are the minority partner, and that's different than where your pilot activity is concentrated in EP 98. So my question is on the scope of the study. Are they trying to de-risk EP 161 before they move forward, or is de-risking your position in EP 98 sufficient to move forward with the MOU? Yeah, so really good question. We see the rocks between EP 161 and the pilot area on the EP 98 being very similar in the deepest part of the basin. So you've got two depth centers, one on the east where the 161 block is focused, and then the second big depth center is on the west part of the basin. And so we have data from the last horizontal wells that had been drilled on EP 161 in 2021, in which we flow tested greater than 90 days on both of those wells. Really, that information guided us toward the SS-1 stimulation 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 partner Santos on EP 161. So in a lot of ways, we're able to de-risk the EP 161 opportunity through what we're doing on EP 98. This is part of cracking the code on the completion design. So as far as the NTLNG expansion that we're working with Santos, 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 finished with Santos over the course of this year. What's the path forward for de-risking 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 EP 161 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 I think it's important that we bring along our partners early in the game so that when we think about a northern pipeline connecting the Beetaloo to Darwin, we do that in collaboration with all of our operators in the Beetaloo, and that's part of the push by Tamboran to include Santos as part of their Darwin 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 Hanold 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? Based on your conversations with your service providers, is that something that they've encountered elsewhere, or is it more a dynamic of learning the Beetaloo? 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 after we pumped the fifth stage on SS-3. We detected a stress anomaly, and we ran back in after we paused the stimulation operation with an acoustic tool and a camera to get some better information about what the stress anomaly was. Out of abundance of caution, what we decided to do is reinforce that section and in parallel continue the stimulation on SS-2 and move forward with the well test on SS-2. We expect after we finish the well test on SS-2 to move back on SS-3 and pump the remaining 60 stages on SS-3 and get a flow test in June. That's the plan. Now, what that provides is an opportunity to take the learnings from SS-2, both on the completion side and what we see on the flow test, and deploy those learnings into the 60 stages we want to pump on SS-3. 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, Eagle Ford in the U.S. The service providers that have been advising the company on this have a lot of experience, have a lot of knowledge, and we don't believe this is an issue with high confidence that we can resolve. Again, we have a sharp eye on safety. We have a sharp eye on attention to detail. And so when we saw this slight anomaly, we focused on identifying where this was coming from in the vertical section and looked to remediate. So that should give you a little bit of color. Okay. No, I appreciate that color. And I guess my follow-up question is just on the stimulations in general. I know you've, again, maybe gone a little bit stronger on the frac than initially thought and maybe backed off on the final decision. But can you discuss some of the rationales of the variation between some of the original plans and how you're going to frac this? Is it service availability? Is it timing? Is it what you think the reservoir can take? Just give us a little color around how you dialed into that number and why it's kind of moved back and forth a little bit. Yeah, sure. Great question, Scott. So we went in with a what we're calling Tamboran V2 design where we were looking to target stimulation intensity of 2,800 lbs per ft, pumping unit up to 100 bbl a minute, and we tightened up the spacing on our design when we had a shorter lateral on SS-2, so we took the opportunity to tighten up the spacings from what we saw in SS-1, which is about 165 ft-1 30 ft. Once we started pumping in that 130 ft spacing per stage, what we saw was stress shadowing, and we were having a little bit of trouble placing all the proppant, and so we optimized that completion kind of real time, and so we made the decision to go back to 165 ft spacing on our stages, and I was really pleased to see the placement of all the proppant we were pumping. We ended up placing about 500,000 lbs per stage. We were able to see kind of the 2,800 lbs per ft once we opened up the spacing a little bit and pumping in 100 bbl a minute. I think what gave me the most encouragement is the last 15 or so stages we were consistently pumping above 2,800 lbs per ft. Last 10 stages, we pumped right at about 3,000 lbs per ft and up to 110 bbl a minute. So what that has really shown us is some learning around kind of the right stage spacing so that we don't get into the stress shadowing between the stages. Again, one of the learnings that the Marcellus operators went through early on is how do we get our stage spacing right. Within this SS-2 well, we were able to have real-time learning to really optimize this completion design. I'm feeling very good about kind of the next 60 stages for SS-3, taking this learning forward. Got it. Appreciate that color. Thank you. Our next question is from Charles Meade with Johnson Rice. Please proceed. Good morning, Joel and Eric and to anyone else on the Tamboran team there. Joel, I want to pick up on Scott's line of questioning. And I think the graph he 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 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 shadowing between the stages. Does that suggest to you that you've got maybe a slightly more permeable rock there than, let's say, as a typical U.S. onshore and conventional? And so that's what calls for the bigger stages. And did you add perfs to be able to put away all that sand when you liked them in the stages? 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 and proppant with wider stage spacing is due to the quality of the rock. So higher porosity and higher permeability are two elements of that. One of the things we're really excited about, again, part of our analog that we've always talked about is how the Beetaloo Shale looks very similar to the Marcellus. And so we have designed our completions to align with what is working in the Marcellus. That's where we started in SS-1. But what we're finding is the more stages that we pump, the Beetaloo will have its own signature. And the opportunity to dial in on the completion design real time is due to kind of the pressure regime that we see here, 0.6 PSI per ft, due to the porosity, the permeability being slightly better than even you see in the Marcellus. 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 being able to zero in on what is the best completion for the Beetaloo, not just modeling on the Marcellus, but really, this is why we call this a V2 design. This is very specific toward the Beetaloo. 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. We recognize we have a much shorter window to get down the curve. Teams doing a great job, Beetaloo and Ops team down in the field working side by side with Liberty. We're doing real-time modeling as we pump every stage. This is what 21st-century modern oil 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. I'm incredibly positive about the reception that the rock is receiving based on this design. It gives me a lot of encouragement as we think about SS-3. 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, it says total gas average 7%. Is it gas fill 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 it's a little obscure to, I think, most of us on the call. And perhaps wrap into that answer, you made mention of farming out to maybe in the back half of the year or two 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 E&Ps, but also consumers. But maybe that's not the case. And maybe you could just elaborate on what you're seeing domestically there. Yeah. So 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, we've seen moratoriums in New South Wales and Victoria. No new exploration really to be heard of on the East Coast. And a major producer into the domestic market has been the Bass Strait field that's operated by Exxon. And 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 has been very consistent in that 2028 to 2030 time period when you start to see significant shortfalls. And so what we're trying to do is get out in front of that. We think a pipeline from the Beetaloo to the East Coast to Bass Strait, this domestic market, will be key. We know that LNG import terminals are being discussed among various gas suppliers as a solution. We think that is not. We think the pipeline from the Beetaloo represents a much better solution for the Australian consumer, given that there's a potential for lower-cost gas moving into the market versus importing LNG from outside of Australia, in addition to lower emissions. So here in Australia, we're very focused on reducing costs to the consumer. We're very focused on reducing carbon emissions. And the Beetaloo pipeline that we'll target as early as 2028 checks both of those boxes. Just to give you a little bit of color, the imported LNG represents about five times the amount of carbon emissions versus a pipeline from the Beetaloo. If you want to reduce carbon emissions here in Australia, having a big pipeline from the Beetaloo to the East Coast is the solution. Our next question is from Jeff Gramp with Alliance Global Partners. Please proceed. Hey, Joel. I'm curious to touch on. There was a prior question regarding kind of IP rate expectations or benchmarks, if you will. So it looks like we're just kind of extrapolating results from the 1H, but given the larger fracs 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 fracs to kind of inform subsequent development 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 rates look like over 12 months. That's really where the purpose of the pilot is to see well tests that go beyond 30 days. I think the 30-day IP will give us an indicative view of the uplift that we potentially could see with increased proppant intensity versus SS-1. I think that's the data point I'm looking for. But from there, I think as we move forward through the course of the year, the information from the IP30 will guide how many wells we think we need to deliver that 40 million a day in our pilot. And then we'll start to get zeroed in on what productivity out of this part of the Beetaloo looks like. And then that will allow us to plan for much bigger development as we look at longer duration flow tests 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 well 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 sand, any updates on potential sourcing options there? I know that was obviously a big 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 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 sand washing plant for these follow-up pilot wells as 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 mine, and we're going to be updating the market further as we continue to make progress on that. Our next question is from Anish Kapadia with Hannam & Partners. Please proceed. Hi. 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 forwards, what's your current thinking in terms of best case for financing options and kind of timing of that financing for the Phase 1 development? And 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 some of the positives you're seeing around global LNG markets at the moment. Yeah. Really good question, Anish. So the costs that we have in front of us are two well tests, 30 days each. Each of the well tests is roughly about $2.5 million-$3 million net to the company. And in addition, there's around $10 million-$12 million of completion costs still remaining as part of the SS-3 well. So those are, I would say, the immediate costs that are coming at us to deliver the IP30 flow rates for both of our wells. And I want to stress kind of the information from those two wells will guide how many wells we need in the second half of this year to drill to deliver our 40 million cu ft 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. So the capital associated with the drilling will be determined in the next few months based on what we see from the well tests. We're looking at a range of debt facilities to support the financing of the infrastructure tied to the pilot. We're making good progress on that and anticipating the months ahead to have that financing finalized. Remember that the gas sales 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 source that through debt. That's why we continue to remain focused with various debt providers on that. I will say on the farm out piece, we are entertaining a number of discussions with potential partners, and we'll continue to progress after the year of 2025. Thanks. And just with some of the positive data 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 forwards or kind of any updated targets on where you think you can kind of get to for drilling and completing these wells? Yeah, sure. Great question. So if you look at the two wells, we are drilling at around $10 million per well, just the drilling alone. And based on the SS-2 35 stages that we pumped, that's approximately about $15 million. So all-in drilling and completions 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 a local sand solution. That will be a material cost reduction in the completion side of around $4 million that we see on sand. We also see additional cost savings from bulk ordering equipment. That includes steel, cement, and these cost savings that we see as we get into a continuous drilling program. In addition, on the completion side, there's an opportunity to employ zipper fracs that will allow us to achieve pumping 8 - 10 stages a day. We were pumping five stages a day on SS-2. That's a single well. As we start drilling and completing multiple wells, zipper fracs, I think, will allow us to double the efficiencies on pumping a number of stages a day. Obviously, that's going to translate to cost savings. So I just want to underscore that the company remains very, very sharply focused on how do we reduce costs as we get into a development. We think there's a pathway to reduce costs to around $16 million total for D&C. That is our target. That's our goal. And I believe based on the last couple of wells that we drill here in 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. Thank you very much. I appreciate all the comments and questions. I look forward to a very exciting few months ahead for the company. I look forward to updating everyone further 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.