Morning, everyone. Just a couple more minutes before we get started. If someone could confirm that they can hear me and see the slides, that would be greatly appreciated. The joy of one's own webinar. Thank you very much, whoever that was. Paul. Thanks. It's 8:30 A.M. in Western Australia, 10:30 A.M. in the East Coast. We will commence the webinar this morning. This is the second crack at this. We had a few technical difficulties yesterday where there was a large percentage of potential attendees that weren't able to join. We're rerunning the webinar this morning. Thank you very much for making some time to join for me to have a bit of a discussion with yourselves, as well as present the interim results from the Lorelle-3 horizontal well in the Taroom Trough. For those that have stumbled into the meeting this morning, I'm Stuart Nicholls. I'm the Managing Director and Chief Executive at Elixir Energy. Elixir is a pure expression of the Taroom Trough. We're a listed public company in the exploration and appraisal phase in the Taroom. We've recently drilled a significant appraisal well in the Taroom Trough called Lorelle-3, where we then placed a horizontal into one of the three key reservoirs discovered, gas-bearing reservoirs discovered in that hole, and we put the well on flowback cleanup and test. What we're going to go this morning is we're going to go through some of the interim results, and then talk about what are the next steps for the company, and the exciting pathway forward. Moving on straight to where we find ourselves. As I just described, here is the Lorelle-3 well that we drilled down to top of basement, through the Permian section, which was the primary series of targets for the well. Discovering gas-charged reservoirs, in both the Kianga Group and in the Back Creek Group, within the Permian section. Based on our strategy of being a sort of fast follower and leveraging off the investment of our incredibly internationally renowned neighbor, Shell, who operates under the QGC banner. We decided that after having discovered that we had the presence in both materiality and thickness and quality in the Dunk sands, that we would place the horizontal well into the Dunk where they had been producing meaningful flow rates of oil and gas to surface from that. After completing the horizontal section, we then placed a 12-stage fracture stimulation into the well, and then have demobilized the frac spread, brought on the well-testing equipment, and then commenced a flowback cleanup phase of the well. Something that I really need to stress today is that, I guess looking at the market reaction yesterday, as well as some of the communications that I had with both institutional and private investors yesterday, is that there seems to be a sort of misunderstanding of where we are in this process. Elixir is actually quite pleased with where results currently sit at the moment, in terms of we've made significant advancements on the region's productivity, initial productivities, the completion mechanisms that we've deployed, as well as some of the operating procedures that we've executed throughout both the drilling and the testing phase. The well is still very much cleaning up, and I would say that it has been a bit of an experience understanding in the flowback process of this well. Given that the toe down nature or the well geometry of this well, given that we did follow the reservoir towards down into the Taroom Trough, just the challenges that we've experienced in being able to efficiently clean this well up without damaging the completions that we had spent quite a lot of time and energy, money and research placing in. Pleasingly, the well has performed well so far. We've got quite a bit of work still to do. And we're going to go through some of those results. I must stress that the well is still very much in cleanup phase. When we shut the well in on Sunday morning, the well was still producing around 500 bpd of fluid. That fluid is stimulation fluid. We are confident of that it's not coming from a third-party source somewhere in the stratigraphy. And the reason for that is that we're in a basin-centered gas setting, which is typically, there is no free water leg observed in a basin-centered gas play. We've got the water chemistry and the salinities of the fluid that is being produced. And so we're confident that that is still stimulation fluid. Lastly, we also have The research and development work that's been done on the cores, and that we'll go into a little bit more detail shortly about just that there is no free or mobile water within the reservoir that we have targeted here, the Tinowon Sandstone or the Dunk member of the Tinowon. Lorelle-3, and another understanding is Lorelle-3 is the fifth horizontal well in the basin. It's only the fourth well to actually flow in any meaningful capacity. One of those five horizontal wells refused to flow. And I would say that we have observed significant improvements on some of the neighboring wells in the immediate area. So we see where Lorelle-3 currently is in its cleanup phase, 30 days into that sort of process, where we would consider Lorelle-3 comparable and favorable to offset wells in the area. Also, another thing to remember is that Lorelle-3 is a proof of concept well. There are potentially up to 2,000 well locations in the Dunk Sands on the western side of the Taroom Trough. I am sure that as we move forward, that all the future development wells that may be drilled by our neighbors and other appraisal wells that might be drilled by Elixir won't look a lot like Lorelle-3. We would expect lengths of wells to change, completion strategies to change, completion intensities to change. And so Lorelle-3, I believe, has been positioned in a lot of people's expectations as being more conventional, really, than unconventional. What we're looking to generate from Lorelle-3 is evidence that we can model a commercial field development effectively. And I would say that we've seen the initial evidence or very encouraging evidence that that is going to be the case. Lorelle-3 is a proof of concept. I can assure you that if Elixir was a private company yesterday, we wouldn't have felt that that was an appropriate juncture to be making disclosure. We did say originally that we would put the well on 30 days of flow, and that was the end of the 30 days. We did see a rising amount of disclosure obligation to be able to put out some news about the way that the flows were behaving. Pleasingly, peak rates of the well have been strong. As you can see, and I've annotated in this slide in blue from the announcement that there is a significant amount of fluid still being produced. Peak rates were measured at the highest level of 10.5 MMscf/d equivalent, and then stabilized over the hour at about 6.2 MMscf/d equivalent. The well was also producing circa 800 bbl of stimulation fluid back during that time. The well has recovered 34% of its total injected fluid, which is high for offset wells that we understand in the area, and we would consider that a positive. All of that fluid, once it has moved out of the well, and we're going to get that out of the way of the wellbore in two ways, and we'll talk about that again in a few moments. As that fluid starts to move away, we would see gas having an effective pathway to come in straight behind that gas and condensates. I would say it's due to the cleanup phase that we still are largely in, that we have some results that are interim in nature. When we start to look at what are the encouraging signs that we have got from Lorelle, certainly when we start to model what development wells might look like, 2,000 m equivalents. Peak rates equivalent would be 15 TJ/d and stabilized rates at 6 TJ/d. Lorelle-3, because of the process that we have gone on to flow the well back from being reasonably gentle on the sand face and not being too aggressive in pulling those fracs into the well and therefore requiring significant cleanup operations. Lorelle-3 now, post its tubing installation, is actually a production-ready well, which is a really positive aspect given that there are some early-stage development opportunities that are being rumored around the Taroom Trough that we might be able to participate in, either on a standalone basis or on a cooperative or collaborative basis. We're really putting ourselves in a great position moving forward. The Lorelle well, its primary objective was to prove that we could commercially recover oil and gas from the Dunk Sands in the western side of the Taroom Trough. You can see the large Dunk sand polygon that we have mapped off the back of both our seismic, neighboring seismic, and well penetrations throughout the area. When we start to talk about has this met the objectives of commerciality, it's not Lorelle-3 that we're looking at, it's what does Lorelle-3 give us confidence when we start to model what development wells look like. As I said, development wells for our screening economics are largely 2 km in length, not the 1 km of reservoir that we've been talking to at Lorelle-3. 2 km in length. Pleasingly, our neighboring operator has recently just drilled a 2,600-m length well just to the south of us. We're not sitting in a world where we're modeling a type of well that is yet to be executed. We're comfortable that the 2,000-m length wells are a basis of reality in terms of being able to discern commercial production or not. When I look at 2,000-m long laterals, I put an appropriate well cost in there. I look at AUD 3 of OpEx as well as the CapEx required to bring it to market. I can start to see that a feasibility or a screening series of economics would show that a 2,000-m lateral stabilized flows at 3.4 TJ/d Would be largely economic, would be NPV positive. That is a really key thing to note, given that the stabilized flows that we have generated at Lorelle, noting that that is still during a cleanup phase, and so we have had to pick a sample set of information that we think is representative of what we have seen to date from the large amounts of fluid and gas and condensates that we've produced. Those 3.4 TJ/d on a 2,000-m e quivalent basis we would see as economic. Given that the well would model a 6 TJ/d flow, that is where we're starting to see that strong degree of encouragement. It is fair to say that Elixir is pleased with where it currently sits, noting that it still has a bit more work to do. I still think that the best days of Lorelle-3 are in front of it, and I would encourage people to look through some of the interim information as to where we are headed as opposed to where we are right now. To look at it where we are right now would be to have a conventional mindset. To see where we are headed is to really look at this through the lens of an unconventional oil and gas development. We've also recovered gas and condensate to surface, where we've been able to execute laboratory work on those gas and condensates, and they're of an excellent quality. Finally, we've been able to record the additional other flowing conditions and really start to understand and generate significant amounts of IP around how do you maintain completion integrity without having If you had to go and clean out every single well because you pull every frack and every time that you flow it back, you're adding significant amounts of cost over a full field development. This is some of the really critical information that we have generated through this process. One of the key learnings that we have had in this process as well, is that the toe-down nature of the well has probably created a protracted or elongated flow-back and cleanup process. We would largely see that the toe of the well is yet to start to contribute to the overall production system. We're going to be doing some additional work, which I'll talk you through right at the end, about how we're going to get a bit more comfortable with that as a hypothesis and the work that we're going to do to ensure that we bring the full well online. In the future, we would largely want to be toe up. I think that that was probably, as I said, one of the key learnings. Rather than drilling west to east, we would in future probably want to drill the wells east to west. The reason why we've located the well where it is that we've been able to secure land access in that location. Drilling further to the west from where we are would've limited us with the amount of reservoir that we have in the westerly direction. There's a few nuances to why we've got what we've got. I'm pretty confident that now that we know some of the challenges that we have to overcome in order to be able to bring the full well into production and be able to generate the significant flow rates of oil and gas, that we can even declare Lorelle-3 as a well commercial. That's all in front of us right now and is still the list of things that we're trying to achieve in the second phase of flows. When I talk about that oil and gas that we flow to surface, the gas that is of excellent quality, about as good a quality as we could hope for in this setting. The gas is about as rich and as calorific as it can be without being too calorific and requiring to be diluted down, so to speak. That is showing us that we've got a gas volume to a sales conversion of about 1.21 or 121% uplift from a million standard cubic feet a day to terajoules a day. That's awesome. That is because we've got really high amounts of ethane, propane, and some good butanes in the gas stream, along with a predominant methane source, and then very little impurities in CO2 and nitrogen, around about 1% or so. Also, the condensate that we have flowed to surface, which has been a really interesting challenge for us. The condensate presents as a hybrid condensate light oil. You can see with an API of 47.8, which would indicate that it's more of a light oil than a condensate, but it's certainly a condensate. Through some of the fluid work that we've done on the core that was retrieved to surface, have noted that about 10% of the ingrained fluid inside of that core was oil, so liquids at reservoir conditions. This fluid that is coming to surface is likely expressing itself as a mixture of fluids, which is why it's probably got quite a significant heavier backend to it. I think if people recall some of the Shell publicity that occurred earlier in the year, they were talking about having up to a 35% diesel fractionation from their condensate, which is an unusually high backend to have in a condensate. We would see that same thing here, very similar colors, and APIs, et cetera. The condensate itself has come and gone throughout the flow testing periods at different periods of different flow rates and at different pressures. That is, we're really sort of honing in on that, I would say, over the last 24 to 48 hours as to some of the reasons why that might be occurring. There's obviously reservoir dynamics, and then there's also downhole well geometry questions that we're asking ourselves. We have certainly seen the condensate being produced at much higher rates, when we've seen high gas rates, and then the condensate almost disappear at lower gas rates. For the moment, based on the data that we have, we would say that we have approximately a 10 bbl/MMscf condensate-to-gas ratio. That is lower than what we would've expected going into the flow testing or the flowback of this well. We would expect, as we move into the second phase of flows and we are able to flow the well with lower simulation fluid going forward at higher gas rates, that we would start to see that condensate-to-gas ratio rise. Okay. Moving on. As I said, the Lorelle-3 is a comparable and a favorable well when we start to compare it to some of the other wells. The market response yesterday, as I said, looks more like a outright conventional oil and gas duster. Certainly, that is not the case in any way, any stretch of the imagination. We have confirmed that we have Dunk sands which are only sort of circa 10 km north from Shell's most northerly penetration, that exhibit the same petrophysical qualities, that have the same hydrocarbons present within them, and that we can flow at high rates. There is some execution of our well geometries as well as our flowbacks that we are going to need to improve on in the second phase of this testing process. I think that the Lorelle-3 well will be an exceptionally good well and will be a benchmark moving forward as we start to really start to demonstrate what this well is capable of in the second phase. When we look at it, compared to Canyon and compared to some of the offset wells I've just described, at very similar stages in their life cycle of flowback, we would say that based on the peak rates and the stabilized rates, that we have been able to generate from the Lorelle well, noting the enormous amounts of fluid still recovered from this well, that at the time that those rates were measured, that we are quite pleased with where we find ourselves. Lorelle will be an evolution. As I said, it will be a step towards longer wells, higher completion intensities, or you might have more fracs with more smaller fracs or less bigger fracs. Those tests and those trials will come over time. We have seen in a couple of critical analogous areas like the Beetaloo and the Montney, which we've been using quite heavily to be able to educate ourselves as to where we are in our processes and where we are going to be headed. When we look at the Beetaloo Basin, hats off to the crew over at Tamboran and Beetaloo Energy and to Santos. They have been plugging away for 10 years, amongst Origin and other people that have been around the area. You can see over the generation of well designs that they have employed, they've been able to increase their initial productivity rates tenfold without increasing the price of their wells tenfold. That is a really critical thing that I think that everybody needs to understand is that Lorelle is a well that we will do a significant amount of learning and modeling from. It does have a very prosperous future in front of it, and may perform much stronger in the second phase. Right now, where are we in comparison to the evolution of other unconventional basins in the area? I'd like to think that we're in a pretty good spot. When we go to a much more drilled-out area like the Montney. Here's 10 years of Montney drilling. You can see the evolution there as well. They've been able to increase their initial productivities 300% over those 10 years. Initial productivities and ultimate recoveries have a very strong relationship with each other. They're getting more gas sooner from every well that they've drilled over that period of time, and that's from 3 km laterals. Where do we sit on a standard cubic foot a day equivalent basis? I would like to think that the term right now is demonstrating that it is a significant global opportunity for unconventional oil and gas development, particularly given the significant amounts of infrastructure and market access that we have in both the domestic and LNG markets right on our doorstep. Those are a couple of things that I'd like investors and shareholders to really have in their mind as well. Now, we started to receive some of the key laboratory information about the core as we moved forward through that flowback and cleanup period. One of those really interesting pieces of work that was done is that basin-centered gas is a reasonably special phenomenon. Let me try and explain it to the generalist out there. As the oil and gas is being generated in a basin-centered gas setting, the reservoir starts to heat up beyond a normal and traditional thermal gradient. That creates a vaporization of the water in That is captured inside of these sandstone reservoirs throughout the Permian section. As that water vaporizes, it starts to move, find degrees of permeability towards the edge of the play, and then it starts to move its way out of the Taroom Trough. What you are left with is a hydrocarbon-saturated sandstone that has been effectively baked very heavily and that is void of moisture and void of fluid. That results in a desiccated or dehydrated series of clays and sands. This phenomenon is common in some unconventional basins around the world, the Beetaloo Basin, for instance, as well as the Montney, some of our key analogs that we've been looking at. The core that we captured, we took 18 m of whole core from the Dunk Sands through our R&D program as part of the pilot drilling in the Lorelle-3 vertical well. We passed that over to a subject matter expert at Core Lab who has been able to pull apart the rock itself and to discern that our clays are in fact dehydrated, and we can confirm that through physical evidence that we've been able to generate at surface. That's a really important aspect of this. What happens when you now fracture stimulate a fully dehydrated reservoir like the Dunk Sands that we have, is that the reservoir wants to take all that fluid in. What you get is you get effectively a water block on your near wellbore permeability. That water block creates a reduction in pathways for gas and oil to make their way into the wellbore and flow to surface. Really the initial phase of flowing that you have is not representative of what the well should be capable of. Positively, using clay stabilizers throughout the fluid process is that the fluid can actually start to migrate. What you see is the science of a concept called soaking. Soaking is going to be a really profound and unique opportunity for us here at Lorelle. If you can imagine a sponge that might have been sitting in the sun for a long period of time, or if you had placed it in the oven or something peculiar like that, it starts to shrivel up into about three quarters of its original size or two thirds of its original size. If you place water on the center of that sponge, it will be absorbed into the center of the sponge. If you come back five, 10, 20 minutes later, you'll see that fluid has actually started to make its way out towards the edges of the sponge and has started to liberate the areas. Saturation in the center of the sponge has reduced, and you've now got a more even distribution of fluid as it's dispersed towards the edges of that sponge. That's exactly how soaking works or the imbibed gas production that we have through water block through the fracture stimulation process. The people that have done the work on our dehydrated and desiccated clays and sands here are the same people that did the work for Tamboran in the Beetaloo Basin. Soaking has been employed quite effectively in the Beetaloo. I've included some links to some literature for those that like to have a good and long read before bedtime. What we see here is a couple of soaking periods that we've been able to pull out from public disclosures. two days, 21 days, 150 days for various operators such as Santos, Tamboran, and Beetaloo, and the improvements that they've been able to generate from the second phase of their flow testing. We've seen anywhere in the Beetaloo Basin from 30%-200% increased gas production from different periods of time of soaking. When we start to look at some of the literature around the Montney, the Montney has zeroed in on about 60 days being the appropriate period of time. It doesn't look like soaking is a linear process, more time equals more effect. You probably get quite a decent amount of effect in the first 60 days, and certainly the Canadian operators have looked at that at the intersection of economics, time, operations, to be able to say that 60 days is an appropriate period of time to soak wells. When we take an example from the Montney, provided by our subject matter experts, of real data so that you can see exactly how that works. A 67-day soak done on a Montney well here shows that over that 67 days when the well was turned on, nothing happened else at the well except it was flowed for two and a half days. It was shut in, it was reopened 67 days later. There was a 44% improvement in gas production, a 67% reduction in fluid production, 290% increase in the modeled ultimate recovery as a result of the reduction in water block and the increase in relative permeability for gas to be able to make its way to the wellbore. That is the science that we are looking to employ here at Lorelle. As I said, at the time of shutting the well in on Sunday, we were experiencing still a very high degree of fluid production, circa 500 bpd of fluid production. We see that Lorelle is a fantastic candidate for that soaking. You can bring that water out of the reservoir in two ways. You can do it through very long-term extended production testing, which also will produce and deplete the oil and gas that is around it. You can do some soaking and do it in a mixture of that flowback process as well, that's exactly what we intend to do. Moving forward, what we are looking to do, we've just finished that first phase of flow testing. We're going to do a whole bunch of analysis on how that has gone. We, in fact, injected specific chemicals into each one of those fracture stimulations. We're going to be able to do a bit of analysis now that we're going to get some of those traces back, those traces will tell us what part of the well that we've been talking to. We're reasonably confident that it's going to show that the vast majority of gas production and fluid production has been coming from the heel of the well, this toe down geometry that we've got is requiring a longer period of time. We're also going to soak the well so that a portion of the water that we are flowing back to surface will actually percolate and dissipate into the reservoir from the wellbore. That should mean that we can start to generate higher gas rates, which will support fluid production from the toe of the well as well, and allow us to really start to demonstrate what the full capability and capacity of the Lorelle-3 well will be. That will increase the data set, the modeling that we've got of initial productivities and ultimate recoveries to allow us to start to work on our reserve bookings with our reserve certifiers. That's the current process that we're going to go forward with. That flow test, that second phase of testing will commence on the 1st of October. All the equipment required to commence that testing is remaining on site. There is no alternative operators that are taking or cherry-picking the bits of kit that we need. We are comfortable that we'll recommence that test on the 1st of October with the bits of equipment that we need to have there at that time. I'm happy to answer any questions at this point, but really stress to you, Lorelle-3, still very early in its results. I would take yesterday's disclosures as encouraging steps in the ultimate area in which it will last. Lorelle-3's best days are in front of it, and I can start to see a commercial development in the Dunk Sands where we use the information from Lorelle-3, and we model that against what future development and production wells will look like. I'm happy to stay on the line for another 30 minutes. I think I can accommodate to ask questions, noting that there's been a reasonably fulsome amount of information provided today. I'm just going to open the Q&A box, and I will read out a question, and then we'll go from there. Justin has asked, "What post-soak stabilized flow rate from a Lorelle-3 or equivalent on 2,000-m development lateral do you need to see to commit to a pilot development?" As I said, 3.4 TJ/d stabilized from a 2 km lateral is reasonably where I see NPV positive. You'll want to see a rate of return on top of that to just, and plus contingency and various other things. I model that at an AUD 9/GJ gas, Australian dollar a gigajoule gas price to be able to start to get comfortable that we've got a pilot project at the Lorelle location. I hope that answers your question, J.R. If the well was producing 500 bpd when it was shut in, how much gas was it producing at the time?" That was when we were starting to bend down the well. It was producing a bit over a 1.5 MMscf/d as we bend it down to 500 bbl. John Bishop, "What insights do you have on the other operators in the trend in terms of how they are designing completions and flowback strategy to manage the liquid hydrocarbons in the reservoir?" It's a good question. Really, we are trying to replicate the results generated by our next door neighbor, QGC or Shell as they're more commonly known. There's not a lot of public disclosure, as you would understand from them, particularly on their IP or their technical basis. They're protecting themselves and the investments that they're making. There is a Taroom Trough Development forum that has been set up by the Queensland Government to create a forum or a platform for more data sharing, learnings to be able to be shared, to be able to accelerate and amplify gas and oil production from the Taroom Trough, which you can see the Queensland Government recently putting AUD 19 million in their budget towards setting up that body to facilitate that work. I would think that we would recognize that Shell's best well was drilled toe up. That is, as I said, is a key learning. It doesn't mean that Lorelle-3 can't replicate those results. It's just more of a wrestle to get it to the same point in time. We're fighting against circa 50 m of vertical relief from the heel to the toe to be able to do that. The Queensland Government has publicly endorsed a fast-track approach. Next question from John Bishop. The Queensland Government has publicly endorsed a fast-track approach to commercializing the Taroom with some ambiguous targets on record around numbers of rigs, et cetera, within a short timeframe. Do you have any insight in the near term as to what your neighbors are planning in terms of larger scale appraisal or pilot development? That's an interesting. You'll note that I've had a bit of a reference to Lorelle-3 being a production-ready well. We believe that there is a significant pilot project being prosecuted in our immediate area, and that pilot project might create the opportunity for cooperative and collaborative development, where we might be able to tie our well fleet across to that. We're working on our own standalone pilot project as well in parallel, in case those cooperative and collaborative outcomes don't materialize. The scale of that pilot, I would say, would significantly dwarf what we are looking at, and that would create maybe an opportunity for Elixir to be in a short-term development to production strategy as well. If you refer back to our May 2025 strategy presentation, Phase 3 of our strategy was about generating small scale production opportunities, potentially through cooperative and collaborative development, is how we would see that. Omega currently has the H&P rig that Shell imported that we used, and Shell just drilled their three wells, which are being fracture stimulated in production test about now, should I say. Omega's drilling, I think, four vertical wells and a couple of laterals, and they're going to production test those on the eastern side of the Taroom Trough. Note that our ATP 2044 Daydream-2 permit actually crosses the Taroom Trough onto that eastern side as well. We do have exposure to those results, and they do reflect on a portion of our acreage in the Taroom Trough. Something to watch and stand by. I think I wish them all the success with their program. We would see an increase in value and a de-risking of a portion of our acreage as a result of their success as well. Some new posts. Jason, "How long will the flow testing period run in October, and if it overlaps the options expiry?" That's a great question, Jason. The options expire on the 17th of October at AUD 0.12 a share. The flow testing will start on the 1st of October of this year. I think that if we see a material increase in productivity, we will be very clear and early on in that phase to make sure that the market understands that the soaking has been successful. That would give a window for a re-rating of the share price to go back to where it has been trading before, to unwind the concept that this well has been a failure in the market's eyes, and then to maybe potentially see those options move into a point of value and give the option holders an opportunity to exercise those. Hopefully, all fingers crossed, Jason, that we are giving you some good news in early October. Sounds like you are an option holder. Sarah Kerr, "Where is Lorelle-3X currently sitting on your P90, P50, and P10 range outcomes?" We haven't where our range of outcomes sit, Sarah, so I'm going to probably defer that. Really where I would focus your attention is that do we believe that we're going to have the information at the end of this process to be able to model commercial development and therefore be able to book reserves? I'd say we still very much believe that that's the case, and we're pleased where we see results at the moment. That probably zeros in somewhere for on your mid-case, I would expect. Dave, "I think it would send a strong signal if the directors were to buy shares on market. It would demonstrate confidence in the company and help stabilize the share price." Thanks for the advice, Dave. Richard Cook, "You said you will in future do a toe up. What is the main reason for the preference over toe down?" Richard, that is just the gravity-fed water production. As you can understand, 50 m of vertical relief from the heel to the toe means that to push the fluids up, you get drainage into the toe of condensate oil and stimulation fluid. The fractures at the toe of the well have to work overtime to get into gas production to get to that circa, call it 1 million- 1.5 million scf/d for that critical lift of fluids out of that toe to then start to roll forward and grow their gas production. I would note that 60% of the well sits on the downside to the heel. Okay? That's the degree of magnitude that we're talking about with heel versus toe. Justin said, "And if the retest comes in below that number, what is the realistic path forward from there?" We're basing ourselves on the science, Justin. Like I said, we've seen some pretty encouraging signs where flow rates at the moment alongside all of that fluid production, which will subside. It is a finite amount of fluid. Ultimately, that fluid will liberate additional gas to come into the wellbore. Given that we are already largely above a point of commerciality, I would say that I'm not looking at the retest coming in below those numbers at this point in time. I'm looking at can we actually declare that the Lorelle-3H well itself is commercial in nature, not just modeled development wells. Do we expect any further announcements or results from the analysis of the Lorelle-3H between now and the test in October? Yeah, like I said, we're going to be doing a lot of technical work. When you're in the day-to-day operations, it's sometimes hard to sit down and apply the appropriate degree of scrutiny analysis to the data that's coming in versus some of the subject matter expert opinions that you're getting in from the side. This gives us a really nice opportunity now to absorb all the flow data that we've been able to generate, look at a lot of those key pieces of information like tracer analysis, which we would expect to start to receive information back on that in the next two weeks. Then start to understand exactly where we sit in terms of the evolution of the cleanup of this well and what is going to be coming forward in front of us. What next after Lorelle-3H? Well, Jason, we've got more Lorelle-3H to do. I would like to think that that will declare a really clear path forward of what happens after that. Daydream-2 is a question that you've got around there. We are still monitoring Daydream-2. As I said, this soaking science, has been generated from the R&D program in the Dunk Reservoir. We have also collected sidewall cores of the Lorelle Sandstone from the Lorelle-3 location. We're going to do some additional work on that physical piece of reservoir that we have, and we're going to be able to understand, is there a soaking effect in the Lorelle Sandstone as well? It's quite a different sandstone to the Dunk. If you were to open Daydream-2 now, almost two years after its last flow test, could we expect a materially different result? We would like to see if that is the case, Daydream-2 could be completed for future production operations. As I said, there might be a material pilot development in our area. Between Lorelle and Daydream-2, we would have a couple of production-ready wells that we might be able to tie in and to generate some small scale, but initial cash flows, to get the business moving forward with a higher degree of momentum. Pleased to talk to you, Jo Cox. "Put capitalization and capital requirements going forward." Let's start with the capital requirements, Jo. We've met all the work commitments of all of our permits, and we've largely completed our 2026 capital program as well. As a result, the only thing that we have left that is of any material expenditure, is the Lorelle-3 second phase of testing. That's, call it AUD 500,000 a month or so to be able to do that. Call it AUD 1 million of budget that we're going to allocate to that. The last quarterly demonstrated that we had AUD 8 million of cash, AUD 2.7 million of undrawn R&D funds, as well as increasing our R&D facility for FY 2027 by AUD 2 million to capture the expenditures that we've been making in this year. In October, November, we would be expecting to receive our tax return back. Our tax return includes, AUD 12 million of R&D tax refund receipts that we've generated and had audited by our R&D partners at Ernst & Young. That would then liberate the repayment of the AUD 10 million facility that we've got, as well as a AUD 2 million cash injection at that period of time. So that's how we're managing our cash flow going forward. You can base your assessments on our balance sheet on that data. Any updates on Diona from Hugh? We're not really here to talk about Diona, but we've seen an encouraging increase in wellhead pressure confirming the overpressure nature of the reservoir there. We're still working through the joint venture with Xstate Resources to be able to design the appropriate artificial lift process there to book that in and then get going on that final phase of testing for Diona. The contingent resource booking for Diona continues to be worked on between Elixir as the operator of the joint venture and Sproule RCE as our resource certifier. Sorry. How long will the flow testing period in October run for? We are going to make that decision. We're going to budget for up to 60 days, but we're going to be pretty comfortable to be adaptive as what we see from when the well turns back on. There's no hard and fast expectations I'm going to set around how long that will go for. Stable gas rate, fluid rate, and flowing pressures for commercial development. I've sort of talked about that. We would want to see 3.4 TJ/d or more than 3.4 TJ/d stabilized from a 2-km lateral to support commercial development, which would require a rate of return on top of that. As we've said, we've modeled that at a AUD 9/GJ gas price and using the inputs from our APA feasibility work as well as our upstream pilot production plant work that we've been doing in parallel. That looks like the end of the Q&A. I hope this has been an enlightening process for everyone. Apologies again, about the breakdown of the webinar yesterday. Only a handful of people, it sounds like, got to witness that. Appreciate that there's been over 100 people there online today. Lorelle-3, we are pleased with where we are at. I have to stress that the best days of Lorelle-3 are in front of it. What you saw yesterday was a snapshot of where we have got to and we believe that we've got quite a material improvement in front of us. That is because we are still heavily cleaning this well up, through some of the challenges of our own making, through the geometry of the well, as well as the process that we wanted to go through the low drawdown and conservative drawdown so that we didn't pull our fracs in and blow up our really critical appraisal well that we have here at Lorelle-3. Lorelle-3 is in great nick. We haven't produced any sand. It's almost production ready. We've just got to clean it up so that we can get that final data from it, to be able to then model that we've got a commercial development and it will stand up to all of the interrogation that financiers like to do to these things going forward. We are excited for some of the potential regional developments that might be happening in the Taroom Trough and how we might participate in those going forward, given that we've got a pretty meaningful appraisal well here at Lorelle-3. That's it for today. Again, feel free to contact me if you'd like. My email address: stuart.nicholls@elixirenergy.com.au. You can send me a text, but do give me some time. I've been having to sort of almost run a call center, because so many of you are so engaged in these results, which is great to have the support of many of you. I just hope to share my time evenly and fairly amongst all of you. Thanks very much. We've got a bit of work to do, but it's not the end of the story by any stretch of the imagination. This is a really important opportunity here in the Taroom Trough, and we're pleased with what we're seeing today. Thanks. Have a great day.