I'd like to welcome all shareholders and visitors to this annual general meeting of Australis Oil & Gas Limited. My name is Jonathan Stewart, and I'm the Chair of the board of Australis Oil & Gas, and Chair of this annual general meeting. On my left is Mr. Graham Dowland, a Director of Australis, and Ms. Julie Foster, Company Secretary of Australis, is present at the meeting. COVID has struck our Board, and hence, Mr. Ian Lusted and Mr. Stephen Scudamore are not present with us in person today, and Mr. Watson. All directors will participate in the meeting via webcast. Mr. Philip Murdoch and Mr. Mark Geoffrey from the company's auditors, BDO Audit (WA) Pty Ltd, are also present, and there are no apologies. Before we start the formal part of the AGM, I would like to take an opportunity to say a few words. Thank you very much to those of you in attendance today at the AGM, and thank you to those listening or watching online, whether it's good morning, good afternoon or good evening. We are an operating oil and gas company with production and a large undeveloped onshore U.S. oil position. The world is early in a period of transition from fossil fuel dependency, and this shift will take time and massive capital investment. We believe our assets are very much required during this transition due to demand, economic fundamentals, location, and short lead time for development. Clearly, the past few years have been tumultuous for the international oil industry. The crash in oil prices from an oversupply into a COVID-19 impacted drop in demand for oil was somewhat of a perfect storm. These conditions, on top of investor-driven demand for returns of cash from oil companies, have seen low levels of new capital committed to oil exploration. The result is and will be a tightening of inventory available for future drilling. The invasion of the Ukraine by Russia, and the consequent sanctions and dislocation have added to supply concerns and delivery complications. Oil demand has improved from the COVID low, and as a result, we have strong oil prices, and importantly for a company like Australis, expectation of higher oil prices for longer. The forward strip of oil prices reflects this. We expect that increasing confidence in future oil pricing will translate into increased demand for quality development opportunities with ready inventory of oil such as that which we hold. Since our last AGM, your board has continued to support our executive team and staff in executing operations efficiently and safely, conservatively managed our balance sheet and ensured commitments are met. Maintenance of our ownership and co-control of our key assets during this difficult past few years places us in an attractive position to seek third-party engagement in an improving market. This third-party engagement is likely to take several shapes over the next period to generate additional activity within our acreage and the broader TMS play. In particular, the successful application of modern stimulation techniques and practices will reinforce the strong economics of the TMS within the core of the play. Our CEO, Ian Lusted, while not here, will, via technology, discuss this further shortly. We will continue to report progress with third-party discussions as and when appropriate. Last year, around this time, I referenced witnessing the green shoots of a recovery in the U.S. oil sector and the maturing of several of the larger onshore shale oil players, and a looming shortage of quality development drilling inventory for players outside of the few large companies that now control the Permian. Financial recovery in the industry is occurring due to improved pricing, but overall, we are still seeing restraint in terms of growth commitments. This position will support stronger pricing for longer, but it does not address future inventory requirements. We believe this will have to change soon. We are grateful for your patience in the realization of our objectives and urge you to stay the course. We will continue to work hard to deliver the value we see in our asset base. Finally, for the moment at least, I would also like to thank, on behalf of the board and shareholders, our management and employees, both in Australia and in the U.S., who've shown considerable commitment, professionalism and skill during the past year. I now return to the formal part of the meeting. As at least two shareholders are present, I advise the meeting that a quorum is present and the annual general meeting is properly constituted. In accordance with the corporate governance principles and recommendations, and where applicable, the ASX listing rules, I declare all resolutions at this meeting will be put to a poll as follows. Resolutions 1 to 12 will be proposed, and shareholders present at the meeting will be able to ask questions on each resolution. However, voting by poll will be conducted following the tabling of all 12 resolutions. Should any shareholder physically present at the meeting wish to ask a question on the resolution, please raise your hand. We will endeavor to answer as many questions as possible during the meeting. As advised in the notice of meeting, shareholders unable to physically attend the meeting were advised to send to the company in advance any questions they may have on any resolution. We have received general questions in advance of the meeting and will attempt to address these during the meeting. Shareholders and shareholder representatives present at the meeting have been provided with a poll form. Upon declaring the poll open, I will ask these shareholders to complete their poll forms. Upon tabling the resolutions, I will disclose the combined ballot proxies received in favor, against, abstaining, and undirected. As chair of the meeting, I intend to vote all available undirected proxies held in favor of resolutions 1 to 11 and against resolution 12. The company's notice of annual general meeting has been provided online for all shareholders to download, has been sent to all directors, the company's auditor, BDO Audit, and those shareholders who requested a copy of the notice. If there is no objection from the meeting, I will take the notice of the annual general meeting as having been read. Thank you. For procedural efficiency, I request that any general questions be left until the formal part of this meeting has been concluded. I now table the financial report for the year ended December 31st, 2021, together with the directors' report and the auditor's report. This is not a resolution. Does anyone have any comments or questions on these documents? As there are no questions in relation to the financial report, I will now ask the meeting to consider resolutions 1 to 12. I advise that the number of proxy votes exercisable by all proxies validly appointed in respect to all resolutions are as indicated on the screen. Resolution 1 relates to the adoption of the remuneration report of the company for the year ended December 31, 2021 as set out in the company's 2021 annual report. Shareholders should note that the vote on this resolution is advisory only and does not bind the directors of the company. In addition, key management personnel and their closely related parties are not permitted to vote on this resolution unless they are voting on behalf of a proxy. The remuneration report is included in the annual report on pages 49 to 80. The Corporations Act requires companies to put to shareholders a non-binding vote to enable shareholders to voice their opinion on matters included in the report. I now invite discussion, if any. I'll move on. Resolution two deals with the re-election of Mr. Graham Dowland as a director. I now invite discussion, if any. Resolution three deals with the re-election of Mr. Alan Watson as a director. I now invite discussion, if any. Resolution four deals with the issue of performance rights to Mr. Ian Lusted or his nominees. I now invite discussion, if any. Resolution five deals with the issue of performance rights to Mr. Graham Dowland or his nominees. I now invite discussion, if any. Resolution six deals with the issue of shares to Mr. Ian Lusted in settlement of the 2021 short-term incentive. I now invite discussion, if any. Resolution 7 deals with the issue of shares to Mr. Graham Dowland in settlement of the 2021 short-term incentive. I now invite discussion, if any. I'll hand over to Graham Dowland for resolution 8. Okay. Resolution eight deals with the issue of fee rights A to Mr. Jonathan Stewart or his nominees in lieu of non-executive director cash fees. Is there any discussion? I hand back to you, John. Thank you. Resolution nine deals with the issue of fee rights A to Mr. Stephen Scudamore or his nominee in lieu of non-executive director cash fees. I now invite discussion, if any. Resolution ten deals with the issue of fee rights A to Mr. Alan Watson or his nominee in lieu of non-executive director cash fees. I now invite discussion, if any. Resolution eleven deals with the re-adoption of the Australis Oil & Gas Limited Employee Equity Incentive Plan. I now invite discussion, if any. Resolution twelve deals with the election of Mr. Kirk Barrell as a director. I now invite discussion, if any. Okay. As all resolutions have been tabled, resolutions one to twelve will now be put to a poll. The persons entitled to vote on this poll are all shareholders, representatives, and attorneys of shareholders who are physically present at the meeting or have submitted a valid proxy. A poll form was provided to eligible shareholders, representatives, and attorneys of shareholders at registration. If anyone in the room is entitled to vote but has not received a poll form, please raise your hand for assistance. Okay. I'll now go through the procedures for completing the poll form. Shareholders should mark the box beside each resolution on the poll form to indicate how and how many votes you wish to cast for each resolution. Proxy holders have been provided with a summary of voting instructions that details the votes to be cast on the resolutions for which you have been appointed as proxy. When proxy holders and appointed representatives of shareholders have been instructed to vote in a particular manner for a resolution, you will be deemed to have completed the poll form in accordance with that instruction. In respect of any open votes that a proxy holder and appointed representative may be entitled to cast, you will need to mark the box beside each resolution on the poll form to indicate how you wish to vote. Please ensure you complete the registered holder name where indicated. When you're finished filling in your voting paper, please lodge it in the ballot box to ensure your vote's counted. Everyone should be experienced with ballot boxes, given we just had an election. If you require any assistance, please raise your hand. Are there any questions? Okay. Ian Lusted, in the interim, will provide the meeting with his CEO address while the poll forms are being completed and returned. I will deliver the results of the poll following Ian's presentation. I'll hand over to Ian. Jonathan, thank you very much, and good morning, everybody. We appreciate you joining the AGM and for this presentation, and my apologies for not being able to attend today in person. The intent of the presentation today, I'm gonna provide a bit of a background and a description of the assets and strategy for those, for any that are new to the company. I'm gonna give a brief overview of our 2021 and broader performance. We'll have a bit of an update on the US unconventional plays and then a comparison back to the TMS. I'm also gonna talk a little bit in detail about some of the recent operations that have taken place in the TMS, and then I'll round out with a bit of a summary of what we believe to be the compelling economic opportunity that the play represents. I trust you'll find it interesting. Next slide, please. I'd ask you all just to take note of the following disclaimers. Thank you. Next slide, please. The company's sole asset and focus is the Tuscaloosa Marine Shale or TMS for short. It's an asset base that we built up during the period of 2016 to 2019, and we've been maintaining since. There were a number of key attributes of the play that drove our original decision to focus on it, and they remain equally valid today as they were back then. The first thing is Australis didn't want to be involved in exploration. There are actually over 90 wells drilled to date in the TMS, and they've delineated out a small part of the overall depositional area where the reservoir quality is consistent and the rock properties allow for the application of an engineered solution to develop the field effectively. Secondly, I'll explain later that this wasn't a question of us following the herd and then trying to compete on price. This was actually an uncompetitive entry, which means that it was a lower cost one. It meant we could secure a contiguous position and take a disciplined approach to location, again, based on that real data and production performance. It also means the lease terms have been favorable. We've probably got industry-low royalty rates, and that's really important, particularly for early-stage play economics. We wanted it to be a scalable asset, i.e., something that had... was material to start off with but could be increased further. We believe that as Australis, we can move quickly to achieve this and add to the existing position with a bit of a first-mover advantage in a relatively complex leasing environment. Then there were the specifics about the rock, the production history and the location. The wells have been online in the play now for over seven years. This is real data and could be the basis for decline profiles and economic estimates. The wells produce the light sweet crude, so a premium product that commands a premium price. In the last three months, it's been between $4 and $6. The field location relative to existing infrastructure and sales points is highly advantageous, and that leads to sort of multiple evacuation routes for products under full field development and ultimately low transportation costs. Finally, all of the economics that we've presented historically have been around the base case using historical technology, early-stage well costs, and not incorporating any of the upsides that are available to the play that are actually only now starting to be explored by some of the recent activity. More detail on that later. Next slide, please. The Australis business strategy has remained consistent since inception. Having secured the asset with some of the characteristics I just described, the question is: How does that fit within the broader U.S. unconventional industry? Perhaps importantly, our intention of partnering in order to move it forward. Well, the first thing is we highlighted the increasing maturity of the other established plays in previous presentations and how that leads to limited availability of quality oil drilling locations for those who don't already have them secured. Our belief is that scarcity will drive valuations and also interest in emerging assets such as the TMS. That particular trend has continued since our last update, and I'll touch upon that during the presentation. Secondly, and Jonathan touched on this, but broadly, the industry is underinvested and continues to do so for a variety of reasons. It's led to a limited supply capacity in the face of a recovering demand and a recognition of the continuing role of oil and gas in the transition that's occurring now to some sort of carbon neutral future. Also, shareholders have forced a transition on the U.S. public independents away from a corporate focus on growth to one that prioritizes shareholder returns. Ultimately, this has been pretty healthy for the industry. Together with the recent strong oil prices, it's led to quarterly record cash generations and record industry-low leverage levels in terms of debt. Against this backdrop, Australis has striven to maintain our exposure to the unique opportunity that we feel we hold by keeping the scale and control in the TMS area, by retaining a fiscally prudent budget and living within the expenditure profiles, and of course, working hard to secure a partner who's willing to put funds to work in the play. We've been aided in this latter part of the strategy by the entry into the TMS recently of two well-capitalized PE operators. They've helped raise the profile of the play. They're gonna help create momentum, which is a critical ingredient in all early-stage unconventional plays. Again, I'll speak about more of this a little bit later. Next slide, please. For those of you that aren't used to the story, I feel it's important to explain how this is an opportunity for Australis and for our shareholders. How is it that the U.S. unconventional industry has missed this, and why has it not been developed before? The map that you can see on the slide here shows the U.S. Gulf Coast. The location of the established oil plays, the Eagle Ford and the Woodford can be seen there. The Woodbine can be seen there, and the Haynesville being a well-established and busy gas play at the moment. Over on the east side, on the right side in the outline in blue, you can see the depositional area of the TMS. In 2010, activity levels in the Eagle Ford were growing rapidly, and companies sought to try and replicate the success there. They naturally followed the trend around the Gulf Coast and started drilling the TMS. In the Eagle Ford, the early success was in the part of the reservoir where the oil and gas both existed, and this equivalent zone was first targeted in the TMS. Overall the, in the TMS area, it was deeper, and it was hotter than it was in the Eagle Ford. Early results were frustrating and disappointing. They were variable. Some of the initial nameplate entrants into the play, companies like EOG and Devon, in frank reality, they had better places to deploy capital and they departed. For those that were left behind, they sought to delineate out an area where their performance was more consistent. The well results moved them up dip to a shallower and cooler part of the play. By 2014, they had narrowed it down to the small area you can see in red on the map there, where the subsurface parameters and the well productivity actually led to the likes of Encana declaring the play internally commercial. Planning was underway for full field development. In 2014, the oil price dropped from circa $100 a barrel down to $35 or $40. The incumbent operators were all over-leveraged, and they all went through some degree of bankruptcy or restructuring, et cetera. Activity stopped in the play. For a period of over four years, there were no new wells drilled at all. The TMS has a reputation. The EOG and Devon can't make it work. It's difficult to drill. It's deep, it's hot. It drove those who were in the play in 2014 to bankruptcy. The reality is, of course, that if EOG had drilled a well within the red outline in 2011, the play would have been developed by then. The depth and the temperature in the red outline area is now exactly the same as what's encountered in the Delaware Basin in the Permian, where tens of thousands of wells have now been drilled. Of course, Encana would have developed the play in 2014 if the oil price hadn't crashed. In the meantime, the wells that were drilled back then have been on production, and their performance were the key drivers for our initial interest and investment in the play. It's this particular history that led to the opportunity for the uncompetitive entry into the play with the benefits that I described earlier. Next slide, please. So the map focuses down in that core area I was showing you previously that was outlined in red. The leases you can see on the map in front of you are in blue. These full six are actually horizontal wellbores. Those in red are ones that Australis operates, of which there are 31 in total. We actually have interest in a further 15 wells of non-operator wells. Australis today is the largest mineral rights holder. We're the largest producer, and we're the largest operator in the play. In total, at the end of the last quarter, we held a little under 95,000 net acres, of which 38,000 is held by existing production, long-term leases. The remainder is term lease with the expiring profile that you can see in the pie chart in the bottom left. It's a big position. At the end of last year, Ryder Scott, our independent reserve auditor, allocated a mid case recoverable of 150 million barrels associated with the full development of our position. That correlates to approximately 360 net future well locations. At the end of the presentation, I'll talk a little bit about what the value attributable is to each of those. Next slide, please. As this is our AGM, I'd also like to spend a few minutes covering our fiscal and ESG results for 2021 and a little bit more broadly, please. If you could go to the next slide, please. I'll start this slide by saying that I personally am intensely proud of our team and its safety record. During 2021, we clocked over 5,000 workdays as we continued to produce wells, carry out workovers, well interventions, et cetera. All of that was carried out without any safety incidents. We're a small, close team. Safety is core to every aspect of our business. I think the field team deserve a special commendation for the way they've gone about their business, and certainly, they have my thanks. On the environmental front, you can see that 2021 was an improvement on the previous year. In particular, the smaller number of reportable spills, which were a focus for us, decreased. In fact, the only reportable spill we had was an oil storage tank that developed a leak. But it only leaked into the existing permanent containment bunding that we have around all of our tanks, which ensured that there was actually zero emissions to the environment. In fact, the oil was immediately pumped back out again into the production system, into alternative storage and then available for subsequent sales. Australis has proactively reported our Scope 1 emissions for the last three years. In our sustainability report for 2021, we adopted the TCFD recommendations, and we further expanded our reporting now to include Scope 2 emissions. The vast majority of our Scope 1 emissions are actually from the very small amounts of flaring that take place at each location. It is a small amount. In total across the whole field, it amounts to about 0.84 million standard cubic feet of gas a day, and that's spread across 20 service locations, most of which are actually insufficient in their own right to qualify as emission reporting centers. Australis has piloted and investigated a number of options to try and monetize or utilize those small volumes of produced gas. To be frank, we're always challenged by the cost involved at each physical location. Now for full field development, that offers a variety of options to just, to export gas and commercialize it in marketable volumes. The good news, again, is that there's a lot of existing infrastructure in the area that we can tie into. Next slide, please. Fiscally, 2021 was a solid year for us. The company generated positive operating cash flow in each quarter. Overall, we enjoyed revenues of about $23 million from sales of just over 400,000 bbl of oil. We were using our outstanding debt down to $16 million, and we're able to exit the year, as you can see there, with a cash balance of just over $9 million. The first quarter of 2022, obviously, with the higher prevailing oil prices, was a strong quarter for us. We had an EBITDA of $2.2 million in that quarter alone. It's worth pointing out that on a go-forward basis with the existing forward strip, our existing production has a valuation of about $77 million. We continue to employ a conservative hedge program. It provides protection against downsides sufficient to cover off our base costs, but increasingly is now starting to provide upside exposure as we make use of costless collars. Next slide, please. I think it's also worth spending a few minutes talking about the slightly bigger picture of Australis's fiscal performance over the last few years, and against the backdrop of the pandemic and of course, the economic and operational challenges that resulted. Our key financial objectives are summarized in these bullet points, so I'm pleased to report that I believe we achieved them all. If we think about it on a quarter-by-quarter basis and start with the bottom left graph. Well, first thing is in dark blue there is that without new wells being added, our production has naturally declined. Other than the dip during the extraordinary events of Q2 2020 when we actually shut the field in for almost two months because of the oil price, you can see the dark blue has been on a gentle decline, which is actually flattening as the Australis wells drilled back in 2018 and 2019 reach a steady state production. On this graph, you can also see the impact of that defensive hedging program. The green line shows the realized oil price. This is effectively what we're selling the oil for on any given day in the market. The blue line shows what we're achieving for that period when the effect of hedging is included. During the low and sometimes negative oil price of 2020 Q2, you can see here we were still enjoying healthy per barrel revenues, and ultimately that was obviously very important to the company. The downside to a conservative hedging program is that as the oil price rises, the hedge foot lags. You can see that during 2021, this was the case. It is to be expected, and from our program, it we believe it's still worthwhile because it allows us to safeguard the asset and ultimately that's where we believe shareholder value lies. On the top right, you can see the net debt suddenly reduced over time as we've made amortization payments, which reduced the debt each quarter. The step change you can see there was actually the placement that we did in Q1 of 2021. Over the period, revenue has been roughly steady, as you can see. Obviously, the declining production has been offset by the increasing oil price. Finally, on the bottom right-hand side, our biggest challenge, trying to keep our cost base at least flat in the face of that declining production volumes and increasing market pricing. When viewed over the period, we've achieved that, but it has required constant vigilance and effort, again, particularly by the Houston-based team. In summary, over the turmoil of the last few years, we've managed our balance sheet, we've maintained our exposure to the TMS opportunity, and we've done so, if I say so, with an exemplary safety and environmental record, i.e., nothing's been compromised despite the challenges. Next slide, please. We've talked about the assets. We've talked about our strategy and how it fits within the broader market and what's happening. We've talked about our results in 2021, and I'd now like to come back and talk a little bit about well performance. We provide comparisons regularly and assessments for shareholders, really with the intent of trying to give confidence that the TMS fundamentals are unequivocal and the play can be compared favorably to any of the more established plays, which essentially are our competition when we're seeking a partner. Next slide, please. As always, we try and start with some independent analysis. Last month, one of the U.S. data analysis companies called ShaleProfile released a bit of an update on oil shale performance up to the end of 2021. This is one of the view graphs taken directly off that report, and it shows improvement in well productivity year upon year. The benchmark being used here is cumulative production in six months. You can see here that all of the plays have consistently improved and perhaps not surprisingly, the Permian now leads the pack, and it shows that in six months, it produces on average 118,000 barrels of oil in that period. It's impressive figures, particularly if you look back to 2011 when they started at 30,000 bbl being produced in the same time. What's driving this improved performance? Next slide, please. Two of the key drivers are shown here. These are two graphs taken from the same report, and they show some of the other trends that were occurring during the same time period. The first thing is wells are getting longer. At the top of this, there you can see that the average lateral length has grown consistently as well year upon year. The Williston Basin, or Bakken, is now exceeding an average lateral length of 10,000 ft. The Permian, again, you can see, has actually grown from 4,000 ft to 9,000 ft, over that same 10-year period. The other key change that I'm focusing on here is that we're pumping a lot more proppant. The lower graph shows you the total amount of proppant pumped in an average well. If we continue to focus on the Permian as an example, in the 10-year period, the amount of proppant pumped per well has gone from 2.5 million pounds to 18 million pounds. A 720% increase. In fact, if you combine those two and you look at the amount being pumped per foot, the Permian's increased by 300% in that same period. It's factors such as this, plus of course, improved fracking techniques and higher grading in terms of choosing locations that's driven the improvements that we talked about on the previous slide. If you move to the next slide, please. The same Rystad report actually broke down what I refer to maybe as true rock productivity during this period. In other words, how much oil is produced, in this case, out of 1,000 ft of reservoir exposure. In this case, the benchmark being used is the cumulative oil production over 12 months, and the results are interesting. If we continue to focus on the Permian here, you can see that rock productivity actually plateaued in 2016, and it's not really improved since. Despite the technology advances, despite the proppant concentration increases, and the availability of high grading in terms of drill locations, the rock on a per foot basis has not really improved in the last four years. Now, those of you that know me probably know where I'm gonna go next, but it's if you could just click the space bar again, I'm gonna first overlay the average performance of the 15 wells that Encana drilled back in 2014. These are the ones we use for our type curve. As you can see, it is obviously a smaller data set, but the wells in the core area perform substantially higher than the average of any of the more mature and evolved plays. The Eagle Ford, for instance, at this point in time, it had over 10,000 wells drilled in it. At this point, there'd only been 80 wells drilled within the TMS. If you just press the button again, you'll see on the right-hand side, this is actually the average of the three water-based mud laterals that Australis drilled to reasonable lengths in 2018 and 2019. It was the Stewart, the Taylor, and the Williams. We remain convinced that the well productivity inside that core area is at least on par, if not better than the alternatives that are out there, particularly when you consider the early stage that we are in this particular play versus the maturity and the optimization and efficiency in these more established players. Next slide, please. Of course, for economics, well production is only half the equation. The other side is how much does it cost? What are the well costs? Last year, Rystad, another data group, published a study where they looked at well costs on a number of the key plays and how they'd evolved, in this case, over a seven-year period. This graph's actually been adapted a little from all the information in that report, but effectively, it shows the percentage improvement year-over-year of drilling and completion costs on a per lateral foot basis. As you can see, but in that seven-year period, there's been a 37% improvement in overall well costs. Now, the TMS is only just starting this. Back in 2018 and 2019, we were able to drill full-length laterals, drill and complete certain facilities, tie them in artificial lift for $10.5 million. In mid-2021, we actually recost or reforecast those costs. We assumed exactly the same execution performance, but we just went out and recontracted them all. We assumed it was a full field development, and we came out with a $9 million well cost. If we can achieve similar savings to this on top of that, we'd also be looking at $6 million wells. If I go back to an earlier slide where I mentioned the reputation of the TMS as being difficult to drill, is it fair to expect the same improvements? Well, the reality is, so far they've been achieved already. Next slide, please. This is actually attempting to show drilling performance improvement over time. Encana, between 2011 and 2014, actually drilled 27 wells. What we're using here is drill time as a proxy for improvements, but you can clearly see the dramatic changes that they achieved over the course of that program. Basically, the early challenges of the play were being resolved by a regular implemented drilling program. Out of interest, the red oval you can see on the bottom right-hand side there are the two full-length laterals that Australis drilled and completed, the Stewart and the Taylor. In green, you can see the recently drilled Stateline well, the Reese 11H No. one, which I think John mentioned briefly in the intro as part of the fill-in. My thanks, John. You can see that those three wells have continued the same process, and we see no reason why the same efficiencies couldn't be brought to bear in the future as we go forward. I included this slide really just to demonstrate the TMS has already started on that process and we'd expect nothing less as we go forward. Next slide, please. I said earlier on that there'd been a period of about four years without activity in the play. I now want to spend a little bit of time talking about some of the recent activity and John's probably already let the cat out of the bag a little in terms of some of the data that I'll share, but I'll work my way through this and make sure that everybody can hear. If you go to the next slide, please. In 2018, Australis drilled six new wells in the play. If you could press to advance, please. We've previously documented both the successes and the challenges that that program faced. As a team, you know, we learned a lot about the execution of the TMS, and to be honest, we've been very honest about our performance. We believe the program showed for the first time that wells could be drilled on a modern cost basis. We were able to further demonstrate the consistency of well productivity within the core area. Now, we elected to be relatively conservative in terms of using a historical frac design that Encana had employed in the latter part of 2014. We know that the results we got were consistent with expectation based upon horizontal length. Next slide, please. If we now fast-forward to 2021, then a local operating entity of a group called Juniper Capital, called Stateline Exploration, drilled their first well in the play called the Reese 11H No. 1. If you could advance the presentation, please. Now, Australis doesn't have any data-sharing agreements with either of those entities, but we believe that it was important that they were successful in the execution, particularly in the drilling. We elected to openly share all of our operational data with them. We had multiple meetings and presentations, but we sought to ensure that they understood the knowledge we gained, both from previous operators and also our own activities in the play. To their credit, the Stateline team was successfully able to drill a 6,300 ft lateral without major incidents. Timeframe to do so was about the same as our Taylor well. For us, as Australis, this further confirms, if you like, the reduction in execution risk that the learning curve has been able to achieve. Now, John talked about this, but Stateline elected to change the frac design that was used. Rather than the historical design, they used a very modern slickwater design. As you can see on the map, we have actually six producing wells in reasonably close proximity to their well. We actually shut three of them in during the frac to monitor for any pressure communication. It was initially partly as a precaution, just in case the frac itself made its way into our wells and damaged them. But we're also seeking to understand if the slickwater frac would have a different geometry to the historical design that we'd used because, of course, that influences spacing, et cetera. The good news is we saw no pressures, and our wells restarted shortly after the frac had finished. Again, John touched upon this, but the frac itself went well. Stateline were able to execute without any major issues the modern design, and they elected to take a very different approach to artificial lift by installing this electrical submersible pump or ESP for short. Now, we don't have access to any detailed production data that I can share. John just touched upon that. Last night they issued their IP24, 1,800 bbl of oil a day. That's undoubtedly a record for the field and obviously is a great result. It's difficult for us to make comparisons because we don't know how they've operated the well in the intervening period. What we can say is that the slickwater frac appears to have worked. It's been very effective on initial reservoir deliverability, which is important. We still remain unsure as to whether the ESP is a viable artificial lift mechanism in the TMS, and we'll await more public data along with everybody else to understand this. I think the key takeaways is that a new entry to the play were able to drill their first well successfully. The slickwater frac appears to have done its job and improved that connectivity. Next slide, please. The second new entrant to the play, or perhaps I should say re-entry into the play is Paloma Resources. A subsidiary of Paloma purchased Goodrich Petroleum at the end of 2021, and they now own all of the producing well inventory and associated HBP acreage that Goodrich held within the TMS. As part of that portfolio, they have these two uncompleted wells, the Painter and the West Alford well. If you could advance the presentation, please. Those wells, as John said, have both been drilled and cased, but they've never been produced. They've never been fracked. They're shorter wells. They're a little over 5,000 feet each. But it's an obvious first step for Paloma, and they're now planning to move forward with both of those wells. Again, Australis, we have a relationship with Paloma anyway, historically, and we've been very open with operational data and experience, really just trying to aid in the planning and execution of those wells. They're on the eastern end of the play, as you saw on the bigger map just now, and to be frank, they're some distance away from our core position. The subsurface data indicates decent reservoir quality. When we look at the offset wells that are highlighted on this blow-up here, then they're either good producers in the case of three of them or two of them where we've had below expectation, then we know why that they've underperformed. Again, as John alluded to and we put into our quarterly, Australis is actually participating as a working interest partner in those wells. We've had a carry on the majority of the sunk costs to date. Building on the successful elements of the slickwater design that Stateline used, the first of those wells has now been fracked and, as John alluded to, that all went according to plan and the flowback started during the course of last night. We'll hope to have new data and additional information to share on that in the coming weeks. Next slide, please. For those of you that know me, this is a dangerous slide because I could get subsumed by it. It's a brief attempt to try and explain how the frac design has evolved from where we started with the Encana design through what Stateline and Paloma did. First thing to point out is that proppant intensity has gone up. To be honest, the old Encana design was actually a relatively intensive frac already, especially back in 2014. Both Stateline and Paloma have increased that intensity. When a well is fracked, it's not all done at once. It's done in stages, working up from the far end of the well. Both Stateline and Paloma have decreased the sizes of each of those stages. For a given horizontal length, they're gonna be more stages. Not only are they pumping more proppant per foot, but they're also doing it in smaller steps. The intent there is to ensure that the whole well length is being equally treated. As already mentioned, Stateline and Paloma are deploying a slickwater design. The viscosity of that fluid being pumped is almost an order of magnitude less than Australis uses for the bulk of our jobs. What that should mean is the fracture complexity increases. Again, the early indications and that IP24 from Stateline would support that. Next slide, please. Now let me stress, everything I was just talking about is about exploring what the upside looks like. Let me finish off the presentation by coming back to our conservative base case. Next slide, please. This slide is quite complicated, but it summarizes what those economics look like. To estimate well productivity, we basically generate what we refer to as a type curve based upon the actual performance of the wells drilled by Encana back in 2014. That occurs, you can see on the graph on the right-hand side, and the top left part of the table summarizes the totals. Well costs, I mentioned those previously. We know we were able to drill wells at $10.5 million. We re-tendered those and came out at a $9 million well cost. For the sake of full disclosure, I think if we went through that process again, you'd see that those costs would have increased. You'll see in a minute that we've been relatively conservative on our oil price assumptions, and we haven't repeated that re-tendering process since. The ownership and the operating costs are all fixed or based on actuals. When we throw all that together and model it out, the single well outcome generates what you see on the bottom right-hand side of the slide. Each well generates an NPV10 of between $8 million and $13.7 million, payback between eight and 14 months. That's for an oil price between $65 and $85 a barrel. Just for reference, the forward strip for 2023 sits at north of $90 a barrel at the moment. Again, obviously at those higher prices, we'd have to factor in some higher well costs. The point I'm trying to make here is that these are compelling base case economics, and that's before we start to factor in any of the upside associated with the improved fracture designs we were just talking about or the well cost reductions that we would expect over time. If you recall from one of the introduction slides, Australis holds 360 net well locations, each one with average well economics along these lines. Next slide, please. This is the final slide, and I've been talking for 30 minutes, so I won't belabor it. The points here hopefully I've made during the course of the presentation. In summary, Australis holds a material position with an increasingly scarce asset type that the industry is being forced to consider. The company's been the lone proponent of the opportunity for some time, but we now have multiple operators putting money to work in the play and exploring some of the upside. It creates interest and momentum that, as I say, all early-stage unconventional plays need. It's been a longer journey than we envisaged, but we remain just as excited and confident in terms of the application of our strategy and the anticipated outcome. With that, gents and ladies and gents, I'll pause. I'll thank you for your interest and support, and I'll hand back to John at the AGM for the final part of today's proceedings. Thank you. Thanks very much, Ian. During the unscheduled internet break, there was a question from the floor regarding what we've learned in the past 12 months. Do you feel that question's been answered by Ian during the presentation, or would you like to ask for further comment? Just one further clarification, please, Ian. Is the recovery your expectation or your forecast on recovery from the wells drilled in 2018, 2019, has that changed over the last 12 months? Did you hear that, Ian? I think so. He was asking whether the recovery's changed at all in the last 12 months. Yeah, whether our EUR recovery rate. Yeah. Yeah. Not in any material way. Every time we put that last slide up, you'll find the EUR changes. It goes up a little bit and goes down, because it just reflects the actual performance of the wells. I'm not sure who asked the question, but broadly speaking, we've seen no changes in terms of overall well performance or expected recovery. Obviously, the jury is still out in terms of the application of more modern frac designs and what they'll achieve. Whether they achieve higher ultimate recoveries, may actually be a moot point. It may be more about producing more quickly and generating the additional value associated with that by a neatly discounted type analysis. Okay. Thanks, Ian. Thank you. Does anyone else have any questions from the floor? Yes, please. I just wanted to know how they're going with the third party. Always talking about a third party to come in. Mm. How is that going? Is there anybody interested or coming? Ian, a question regards third-party interest and our references to third-party transactions. Look, it is. It's an absolute constant focus for us. We've engaged with a number of parties over the course of the last 12 months. We've had several go through diligence exercises. To my knowledge, I don't believe that any of them have not progressed as a result of what they've discovered in the process. We have a number that have either done or are ready to do diligence, but the feedback we've had constantly is that it's been an internal decision on their part not to proceed with, if you like, more traditional M&A. That's the reason we were pointing to some of the market forces and drivers that we think are all moving in the right direction. Obviously, we will make an announcement, and we'll advise the market as and when we secure one. I would say that we are increasingly confident we're going to be able to do it for all the reasons I was outlining during the presentation. We take comfort from the fact that the diligence exercises that we've gone through thus far have not uncovered something perhaps that we've missed or elements of the play that perhaps put people off. It's more been around the macro story and when people are ready to commit to these early stage plays. All the transactions or the vast majority of the transactions that have taken place in the course of the last 12 months have really been around consolidation in the existing plays. Any further questions? Okay. Well, thank you, Ian. In addition to the questions from the floor, the company has received the following questions from a shareholder, Mr. Kirk Barrell, to which I now respond. There are a number of questions asked which revolve around the following themes. Australis well results, the basis for certain staffing decisions during our drilling campaign, our comparisons in public releases of the TMS to other unconventional U.S. plays, staffing levels for current operations and strategy, length of time it is taking to secure a partner, ESG actions and considerations being undertaken by the company. Addressing each question theme, I provide a summary of the question and the company's response. Firstly, regarding well results and the Australis drilling program. Query related to the payout status of the six Australis drilled wells. While some wells have paid out, others have yet to achieve payout. By payout, we refer to revenue from a well having achieved or exceeded the capital cost of drilling and completing the well. The company disclosed in detail the operational activities at the time, and provided an in-depth analysis of the successes and challenges encountered following the end of operations review that took place in late 2019. The query also related to field staffing decisions in 2018 to 2020. We do not believe it is appropriate to publicly discuss field-level decisions on personnel or comment on local gossip which is uninformed and inaccurate. We will, however, state the following: Australis sought out operational field supervisors who had previous experience in the TMS where possible. This included ex-contractors for Encana and Goodrich. We also sought specific knowledge and experience in our planning team, knowing the challenges earlier operators in the play had faced. Mr. Barrell further queried TMS comparisons that Australis makes to other plays, in particular the Permian Basin. Anyone who has taken the time to read our presentation materials over the last few years, including the presentations on our website currently and today's presentation, will see the basis for the Permian comparison as well as comparisons to other oil plays. Staffing levels. In relation to staff, Mr. Barrell's query related to his perception, Australis is maintaining a higher than necessary level of staff to manage the current level of operations. The Australis staffing level is at a minimal level while fit for purpose based on the current company's well-defined strategy and the level of operations we manage. The question on staffing illustrates a lack of understanding or experience in operating a material oil-producing asset. In addition, and as disclosed previously, the company over the past two years made the very difficult decision to reduce staffing levels and costs due to reduced activity levels and during the challenging business environment. The current staff are responsible for managing both the oil and gas operations involving three dozen wells and thousands of royalty owners, and an ongoing land program. The strategic aims of Australis, which requires being able to react in a timely fashion to market conditions for resumption of higher levels of activity, which we see are already starting to occur, and not merely to be a passive leaseholder dependent on external factors. Next is partnering. The query relating to the length of time to secure a partner is a function of the market and industry. Ian's just touched on this. As explained during the presentation and many of the recent Australis press releases, the U.S. oil industry contracted during the low oil price environment that commenced in late 2019, and then it was further impacted by the COVID pandemic. During the past few years, shareholders have forced a change of strategy such that growth was replaced by free cash flow generation and returns to shareholders and investors. It's only now that the industry, with several quarters of rising oil prices considering M&A, primarily due to the high grading of existing inventory. Quality in-house inventory is being depleted. Many in the industry are having to look to acquire such inventory. Common themes in our presentation. Accordingly, we believe our patience will be rewarded. This is an interesting question from Mr. Barrell, a direct competitor in the TMS who has continuously been marketing an acreage position for over six years, much of it outside of the production delineated TMS core. ESG. ESG queries relate to flaring and other aspects relating to reducing emissions. All excellent queries of which mostly are answered within our recently released sustainability report. While our emissions are, at our stage of development, very modest, we've continued to apply technology to reduce the emissions further, as demonstrated in our annual report and in the presentation just delivered. The use of flaring will be addressed as our scale of operations increase. I'll now move on to the poll results. The votes have been counted on resolutions 1 to 12, and I now declare the resolutions 1 to 11 have been passed by the requisite majorities and resolution 12 has not been passed. The results will be released to the ASX immediately following this meeting. As there are no other matters that can be properly considered in the formal part of this annual general meeting, I now declare the annual general meeting closed, and thank you for your patience in its execution.