Welcome, and thank you for taking the time to watch this December 2025 corporate presentation, which we've recently used with brokers, analysts, and shareholders following the two strategic transactions that we recently announced. For those of you that are new to the company, or perhaps for those of you who haven't spent too much time with us recently, I intend to provide a little background on the company, the team, to give you a short history of our key asset, and share why we are still excited by its potential to move to full-field development. Then, we'll briefly discuss the two transactions that were announced at the end of November and how they deliver on all of the key strategic objectives we've been trying to accomplish over the last few years. Overall, that'll take about 15 minutes, and then for those that are interested, there are several additional slides at the back of this particular pack, and they provide more details on the two transactions, or of course, I can refer you back to the announcement which was released on the 26th of November 2025. So, Australis was founded by the principals and management of Aurora Oil & Gas, which was another ASX-listed company that participated in the development of one of the major unconventional plays in the U.S. called the Eagle Ford. That company was sold in 2014 to a Canadian company called Baytex for $1.8 billion. Shortly afterwards, the team reformed as Australis, and we commenced the process of trying to identify a target asset. We had three key criteria: we wanted exposure to oil, we wanted the subsurface to be of a high quality, and we were seeking a very low-cost entry. Now, the combination of all three of these proved to be very difficult to achieve in the established plays. They were basically fully appraised, and so all of the opportunities fell short on at least one of the points. But we kept coming back to the Tuscaloosa Marine Shale, or TMS for short, where unique circumstances actually delivered on all three. So, in 2016, we secured an initial position in the TMS, and then we listed to access the capital in order to close that particular transaction. Between 2016 and 2018, we then built up a large position within the delineated core of the TMS, and we did it through a series of transactions and an active leasing program. It's worth pointing out that acreage was secured at very low rates by U.S. standards. During 2018 and 2019, Australis drilled six TMS wells. They clearly demonstrated the anticipated productivity, and they allowed us to verify some of the subsurface models and the operating windows and parameters in order to drill wells. Our intent thereafter was to use the information we'd secured from the previous operators within the play, and also our activity in 2018 and 2019, to convince a larger partner to farm into our acreage and provide a carry for Australis as the play moved towards full-field development. Unfortunately, first COVID hit, which had a dramatic impact on the oil price and our industry. As the world started to recover from COVID, we faced additional headwinds that were completely unrelated to the asset but very much industry-driven. Finally, in November 2005, we were able to secure a partner through the farming, and we signed an additional transaction to significantly improve the financial status of the company. Before I get to those transactions, I would like to spend a couple of minutes talking about the history of the TMS, particularly in the context of the U.S. unconventional industry, which I think will explain why this is still an opportunity and why it hasn't been developed already. The TMS has many similarities to Eagle Ford. It's located on the Gulf Coast. It has a similar age, and its deposition distribution has been mapped as a result of it being the source rock for multiple conventional reservoirs and fields in the area. When activity in the Eagle Ford took off in 2010, companies immediately started looking for analogs, and the TMS was a fairly obvious target. The part of the Eagle Ford that worked well was at a depth of about 9,000 feet, but the equivalent section in the TMS was much deeper and much hotter at about 14,500 feet vertical depth. Two large companies, EOG and Devon, actually, took significant positions, and they drilled a handful of wells focused on that same area that had worked in the Eagle Ford. It's best to say that the results were varied, and the wells were relatively expensive, so those two particular companies, with other areas to deploy capital, departed the play, and it began to earn a bit of a reputation as being deep, hot, with variable well performance. However, between 2012 and 2014, there were a small handful of companies that remained, and they continued to drill wells. They effectively just followed the results, and by 2014, one of those companies in particular, Encana, had delineated out an area. It's the small sort of red polygon you can see on the top right-hand side of the TMS area there. Within that area, the well results were cheaper, and they were more consistent, and we now refer to that area as the TMS Core. Interestingly, Encana largely kept those results to themselves as they were continuing to lease inside that core and obviously wanted to minimize competition. Now, the chart here shows drilling activity in the TMS, and you can clearly see that the peak of activity occurred in 2014, which is when that delineated core was really starting to be defined out. There were nearly 50 wells drilled in 2014 itself, and that's out of a total of 90 that had been drilled over the overall play. But with only 90 wells, this is still very much in its infancy in terms of the application of knowledge and a learning curve and the improvement that comes with that. The dashed green line you can see is actually the oil price, and you can see the dramatic drop that occurred between 2014 and 2015, primarily actually due to the significant oversupply from the then rampant unconventional industry. You can see that in 2014, multiple operators were busy, including Encana, but they all had one thing in common, which was significant over-leverage. When the oil price dropped, all of these companies, including Encana, had to stop operations in this new and emerging play. We now know that Encana were planning to move to full-field development in 2015. They'd lined up multiple rigs, and the reality is, as if the oil price had not dropped when it did, then it's very likely that TMS Core would have been developed by now. Since 2015, other than the Australis campaign in 2018 and 2019, which you can see in yellow there on the bar chart, there's only actually been one other new well drilled in the play. Why? Well, because the industry made a seismic shift in its business strategy around about the same time as COVID. The industry moved from a growth-oriented model with significant leverage and limited shareholder returns, i.e., one that was all about production growth, to one that became absolutely focused on maximizing those shareholder returns. In order to do that, it moved from a production growth to a production maintenance model and also significantly de-risked their operations. Practically, that meant staying within the established basins and focusing on the available inventory within those basins, and this was as opposed to exploration or appraisal, trying to identify new ones. So, what happened to the rest of the industry in that period post-2014? Well, as you can see in the more established plays, they continued to be developed, and well performance continued to improve, and costs came down. To try and demonstrate this, you can see the bar chart on this particular slide. We've picked out the five key unconventional plays in oil plays in the U.S., and we've actually split the Permian into the Delaware and Midland on this particular view graph. We're using a metric here of barrels of oil equivalent produced by the wells per 1,000 feet in the first 12 months, which is a bit of a mouthful, but it's a fairly common benchmark, and basically, it's a measure of how productive the rock is in the first 12 months, and those first 12 months for an unconventional well is when it produces the vast majority of this higher production rate and a significant portion of its overall recovery. We're using public data, and we've taken the three biggest producers in each of the plays. We've actually taken three years as snapshots: 2014, which is shown in the brown column, 2021, which is shown in the dark blue, and 2024, which is shown in the gray. Interestingly, the pink part of each bar is the gas component of the production, which has been converted back to a barrel of oil equivalent, and that's been done at a 15:1 ratio, which is broadly indicative and a decent proxy for the value of that gas. So, the first period to compare is between 2014 and 2021, i.e., between the brown bars and the blue bars. Now, you can see that every single play improved. In actual fact, the average improvement across the five was 26%. The drivers for this were both technology, which was a significant contributor, and also high grading. As each play was delineated out, the better parts were identified, and these were typically drilled up first. If we then move forward and compare 2021 to 2024, so now we're moving from the blue bars to the gray bars, well, you can see that the opposite occurred. All of the plays actually decreased, this time by an average of 13%. In this instance, the same two drivers were actually in competition with each other. Technology continued to improve and continued to drive productivity higher, albeit it's fair to say that the changes were now becoming more incremental and less step-like. But opposing that was the reality of limited inventory. In all of these plays, as that premier acreage is drilled up, the industry is having to consider tier two and lesser quality drilling locations, and ultimately, that's lower quality rock, and that reduces production performance. During this period, it's clear that that inventory quality has become the primary driver, and that led to the reduction of well performance you can see there. If you take time and review our corporate presentations over the last three or four years, you'll see that this issue of inventory depletion, it features heavily in our commentary. Why? Because it is this issue we feel that is now driving industry participants to consider opportunities outside of those established plays. To maintain production, companies either have to drill more wells or longer wells. To do that, they have to spend more CapEx, and that reduces the amount that they can return to shareholders. Or they have to go and try and find additional new high-quality inventory at an acceptable price, and that's what's forcing them to look outside the established basins and into the new and emerging opportunities. If the industry is starting to look at alternatives, how does the TMS stack up? Pretty well, as it turns out. If you take the same bar chart we were just looking at, but now we show an average performance of every well in the TMS Core. Remember, this is effectively 2014 and pre-vintage data points, and you can see that the wells outperform the DJ Basin, the Midland Basin, and the Williston, and they're on par with Eagle Ford, although a little shorter than Delaware. By 2021, the Eagle Ford and the Midland and the Williston had caught up, but if you then fast forward to 2024, the TMS is outperforming all of them except for the Delaware. Now, there are about 60 or so wells out of the 90 that are inside the core, but there's a subset of about 15 of those wells, which is towards the end of the program in 2014, that represent where the early-stage evolution got to. We refer to those as sort of we take those wells and we use them as a sort of proxy for what we expect production to be, and we refer to them as a type curve, and that's the second red bar that obviously shows an increase. If you compare that to the other plays, then again, we are significantly now outperforming all of the other plays, and on an oil basis, are now comparable with the Delaware. So, it's good productive rock, and that's why when Australis has been targeting potential partners over the last few years, we often met the internal technical and commercial hurdles, but until a couple of weeks ago, we'd not been able to convince a partner to commit to a program in the play. Why? Well, again, we come back to that shift in business strategy that the industry adopted, and I touched upon in the last slide. But ultimately, that new model just isn't sustainable. As that well performance continues to decline and new quality inventory in those established basins becomes prohibitively expensive, then the companies have been forced to look elsewhere, and our recent transactions are a product of both those market pressures and the underlying quality of the TMS play itself. So, on November the 26th, we were able to announce two transactions. They were targeted at different parts of our asset, and each achieved the strategic objectives we have long articulated. The first transaction focused on our undeveloped acreage. It was with a large public unconventional oil and gas company that we've been working with now for over a year on diligence and asset evaluation. That company has added value to our undeveloped acreage position, and they will carry Australis on an ongoing drilling and leasing program to earn an 80% interest on that acreage. Practically, this translates as a program of up to $46 million, which corresponds to four to five wells plus a $1 million leasing program in order to earn that interest. Additionally, the transaction sets up an area of mutual interest or AMI. Within that, we've agreed that any new leasing will be offered to both parties on an 80/20 basis, and this is important to us. Today, Australis holds about 48,000 net acres in the core. When the carry program is complete, Australis will retain about 11,000 net acres, which is still a sizable position, but we've got the ability now, through the new leasing, to grow our position back and to replace some of that farmed out acreage. The second transaction focuses on our producing wells. We've agreed to sell a 90% working interest, subject to standard adjustments that recognize an effective date actually of the 1st of July 2025. Now, unlike the first transaction, which was binding on execution, the second actually has a scheduled closing date of the 31st of December 2025. We're working hard now to make sure we can meet that date, or if not, then very close thereafter. These funds provide a significant injection of liquidity into the company and allows us to fund ourselves during that carry program of the first transaction, and of course, participate in any leasing that takes place within the AMI. We've actually kept 10% of our interest in those producing wells. We're only selling 90%, and we've done that to maintain our non-operator rights and also, obviously, a modest revenue stream, which will go some way to offsetting our overheads before the new wells under the carry program come online, start production, and generate revenue for Australis. Crucially, this second transaction focused only on the wells. There's no impact on the development acreage, and that was obviously important to maintain the viability of transaction number one. So, let's just briefly discuss why these deals are important to us and how they meet our key corporate objectives for this phase of our business strategy. The first and foremost is that transaction one provides validation for the technical basis of the TMS by an established industry participant. That carried work program will advance the play towards full-field development and allow the application and testing of modern technology and methodologies on the TMS for the first time. Hopefully, we can unlock some of that 26% improvement I was shown that the other plays achieved. As a company, Australis has carried with a 20% working interest on all of this work. That'll generate well revenues for us at no cost to Australis, and that'll help us fund the next phases of the program. Transaction two monetizes the majority of our producing asset. This will allow us to repay the modest outstanding debt, and we'll be well capitalized now for all the corporate costs during that transaction of that carry program. It is worth pointing out that the C3 valuation of the combination of both transactions and the asset value associated with it far exceeds our market capitalization, and of course, the company is now fully funded for that initial program without any further anticipated dilution to shareholders, and finally, we've maintained a meaningful interest in the development program, and we've got the ability to scale that up again through the AMI. This is important. It ultimately will generate shareholder value either through participation in that ongoing development program or if we sell the retained interest at some point down the track, so in summary, in the immediate term, we're focused on closing out that second transaction with EQV. We're targeting the 31st of December, but if it does slip, then we certainly aim to get it closed early in the new year. With the development partner, we've actually already kicked off the leasing program, and the planning has now started so that we're prepared for a 2026 spud of the first well in that work program. Look, I hope you found this interesting and informative. I'd remind you that there are several detailed slides in the appendix here, and there's also obviously significant detail in our transaction announcement from last month. Thank you very much for your time, and we very much appreciate your support.