Greetings from Canada. I am Michael Binnion, CEO of Questerre Energy, and I am on with our CFO, Jason D'Silva, for our first presentation of quarterly results to shareholders. Welcome today. We are going to go through a short presentation to supplement or to help explain our results that were just issued, and we will take some moderated questions. If you put a question or a comment in the chat, Jason will be monitoring that, and he can present at the end some questions for us, for him or myself, to try to answer for you. I am going to get Jason to start flipping the slides for me because he is in control of the screen. I think it is worth reviewing that we did a major acquisition in the fourth quarter of last year. The goal here was to be able to advance forward what we think is really extremely interesting technology for refining oil shale and to have a platform to commercialize multibillion-dollar barrels of resources that we have been able to acquire in Utah, United States. We are in the process of reacquiring acreage also in the Kingdom of Jordan and now also Brazil. Adding up to multibillion barrel potential for our company, while we are cash flowing. We think an extraordinary opportunity for us to commercialize a technology with a cash flowing platform. The other key thing for those who have followed us for a long time is that we made a giant gas discovery in 2010 in Quebec, in Eastern Canada, and we have been pursuing a business and political solution there. We think that as we have been saying, we are waiting for the winning conditions politically, and we think that those winning conditions may have now arrived. We have a dual-class structure. The preferred shares have a preferred ownership in those Quebec assets, and the rest of the assets are owned solely by the common shares. Next. Different places that we have assets or operations. Brazil has by far become our main operation with now about 900 employees and contractors. Utah, we have a license and several hundred million barrels of shale oil under license. The main thing there is we have got 15+ years of technology development into refining of oil shale or kerogen. Kingdom of Jordan, we are securing rights. We had a 7 billion barrel claim there. We are in the process of resecuring those rights now. In Western Canada, we have a Montney resource with a lot of undrilled locations after the recent sale of our original Montney discovery. We also have Torquay or Torquay Spearfish type oil in Saskatchewan and Manitoba that we expect to be able to grow over the next couple of years. Then, as I just mentioned, in Quebec, we are looking to deliver value to shareholders out of what is an incredibly important strategic discovery for Quebec. Okay, so next. There we go. Now into the results. I think we will see that we have been able to continue to turn around for positive cash flow the asset that we acquired in Brazil. I would say the main highlights have been that we had a very important test of HCCO, which is the name of our refining technology. It stands for homogeneous charge, so that means an even charge, and continuous oxidization. That means a continuous thermal process that generates heat to refine the rock. We were able to do a test in our new platform, our new operation in Brazil on a full-scale, commercial-sized refining vessel, which is what we are operating in Brazil. The key things there was to show that we could deliver that working gas in a homogeneous way, not have it be uneven, and also that the oxidization was continuous and there was no thermal runaways. We had only been able to test that. We originally were testing it in vessels of 6 ft by 6 ft, and then more recently 2 ft by 12 ft, so 2 ft by 12 ft. So about a little bit less than a meter in diameter. These are large laboratory vessels, but small for the real world. We have now tested it in a vessel that is over a 10 m in diameter vessel. We were able to show that we can deliver that working gas both in a homogeneous way and in a way that the oxidization was continuous without uneven heat or thermal runaway. We think it is a big technical breakthrough. Just to give some people some idea why we felt the acquisition of PX was important for this is because to do that test in Utah, which would have been on a test that was 1/10 scale, so rather than a full-scale vessel, a 1/10 scale vessel, but in the field. We estimated the cost of that to be about $20 million - $30 million to be able to build and carry out that field pilot. We were able to do this particular test at PX for under CAD 100,000. In one sense, we have already gained a value of CAD 20 million or CAD 30 million out of this acquisition, above and beyond what is going to be shown in the results. We also were able to sell some fairly well-developed assets in the Montney that had not that many drilling locations left in them. We sold that for CAD 23.5 million in cash. They also assumed CAD 6.5 million in abandonment liabilities. From a balance sheet point of view, it was a CAD 30 million transaction. I think that we have been, as I said, quite pleased to be able to have disposed of an asset that did not have a whole lot of drilling locations left, so that we can focus on some of our assets with a better future inventory of locations. In the results, you will see that the result was recognized net income from that sale. We were able to sell it at above our value. The funds from operations, CAD 18.3 million, so almost the same as the first quarter. There were a few extra operating costs in this quarter compared to Q1, but it is now the second quarter that we have been able to deliver significant positive cash flow, so we are pleased with the results. In fact, the results at PX Energy were a record profit for that entity, as we understand, in its history. Certainly, in the history that we are aware of, it is a record quarterly profit for PX. Interestingly, and we will go into this in a bit more detail, but it was not generated just by higher oil prices. We had retort production issues related to the last turnaround that happened before we bought it, and that caused some production declines. The higher prices helped offset that. Our revenue was really on budget or close to on budget. A lot of the profit was really delivered by more efficient operating costs and lower cost control generally. The preferred shares were listed on Euronext Growth, and that value is now in the market. As I said, they have a preferred ownership in the Quebec assets. Our average production 5,700 bbl a day. We had a noticeable improvement in working capital, which we will go into in more detail as well. Okay, next slide, Jason. Okay, this gives a lot of details on the production. The main point here is in Brazil is that we now have an operation that is a refinery. We sell through distributors. The distributors are selling directly to end customers. We market our product. We have technical sheets, we have salespeople that talk to end customers about some of the technical advantages of the composition of our fuel oil relative to others. We do have a marketing and sales organization there, and we mostly work to produce to order so that we are producing more or less just on time to meet our customer demand. But in the last two quarters with the disruption due to the war in Iran, we have had some disruption with our customer demand, and you will see here that production and sales have diverged and that we have been holding some fuel oil in inventory. But this slide, I think, gives you a good sense of what was produced versus what is being held in inventory. The parts being held in inventory have not been recognized in our sales revenue as of yet. Okay. Although it is important to note that we do have minimum commitments from our two main distributors, and we have been collecting cash for minimum sales, whether they are delivered or not. Okay, Jason, next one. Okay, this gives you a sense of our financial results for the quarter, just to break down what the reported net income is and reconciling you to the adjusted funds flow of CAD 19 million. Then we also are showing the difference between cash flow to the adjusted funds as well in the two reconciliations. The main items there are both the deferred revenue, which is now under IFRS, referred to as contract liabilities, which we are relating to the future sale of the inventory that we have. The other one is some non-cash items like depreciation, et cetera like that. Okay, that gives you the, I think, the key items there for that. You will see that we have got a noticeable improvement, I think a noticeable improvement in cash, and you will see also a noticeable improvement in working capital. This was not shown in the first quarter. In the first quarter, there were a lot of hang over issues from the vendor or the last owner. A lot of the positive cash in the first quarter went to clean up some of the issues in the purchase and sale from the vendor. They had sold the asset because it was in financial distress. But this quarter, we are really seeing that the cash flow is making a difference to our working capital and cash on hand. I, of course, just mentioning other item that has helped our cash is the sale of the asset in Montney. Okay, Jason. Okay, just to analyze, excuse me, the working capital deficit. There is a lot of current liabilities that do relate, still. As I said, we cleaned up a lot of them in the first quarter, but there is a lot of current liabilities now from the purchase and sale that are non-cash. There is an obligation to assume some of these liabilities through the issuance of shares or the issuance of future shares. We currently are disputing with the vendor many of these liabilities. Our position with the vendor is that we will not have to pay these, and we will not have to issue the shares. This is not final yet, so they continue to be shown in the balance sheet. It gives you a good sense of that with current assets of CAD 87 million and current liabilities of CAD 106 million, but if we were to take out the ones that are not settled in cash and in fact may not get paid at all, there is another CAD 44 million. That relates, I should also divide, a little bit more than half of that is related to PX acquisition, and then the other part is the contract sales or the future sales of the inventory that was lifted but not taken. If you take that out, you see that we have actually got a substantial working capital surplus. Then below, we have now also segmented out the purchase of PX Energy was in one sense, a bit of a no money down deal, that we bought it by assuming debts. We have now separated out here the liabilities that are ring-fenced and that the parent company has no legal obligation for. We will see here that the current assets or CAD 51 million of deficit in Brazil, but if you take out the CAD 44 million, that comes down to actually a relatively small working capital deficit of CAD 10 million, and that in Canada, we have actually running a substantial working capital surplus of over CAD 30 million. Hopefully that will help our shareholders understand much better, one, that there has been a significant improvement in cash and working capital over the quarter, and also that we do have it ring-fenced in that PX platform, which we purchased primarily as a path to commercialization of a new technology. It is well on its way to being a positive cash flow asset itself. Okay, next, Jason. Okay, this helps also. This is the other debts, liabilities that we assumed in this acquisition. We should be clear that there are some disputes with the vendor. Over the thing we are, as I said, our position is that the sale is a legal sale and that we do not owe the vendor the final amounts because of the working capital situation not being as disclosed in the agreement, but the vendor is taking another position on that. This is a reconciliation of the bonds, and you will see that what we are carrying them for on the balance sheet after a number of adjustments for IFRS. Those are a fair market value adjustment, because the underlying interest rate was lower than market, and then also because the underlying interest rate is variable with the price of Brent, there is also an embedded derivative adjustment. Both of these are, in one sense, non-cash items intended to try to fair value what the debt is, and that's the number on the top, CAD 112 million or $79 million. If we take out those adjustments plus accrue for the interest that we're paying in kind during this fiscal year, you'll see that we'll get to the face value of the bonds, which is $80 million, the amount that we truly nominally owe, and then the accrued interest of $6 million. In that sense, in the IFRS fair value accounting under reports the face value of the debt. Next slide, Jason. Just a quick update. We'd found that we had some deteriorating production in the retort refinery really starting in January, February, there's some signs of it. It became worse in second quarter, and we finally got to the point that in July and August, we were down by maybe 30% from the output from the refinery. This, in the end, we've discovered related to a failure in the furnace, that the furnace was not generating and delivering the heat in an efficient manner at all. We elected to, or in fact, I think it wasn't really an election, we were forced to do an emergency shutdown of the retort refinery for a turnaround. The net cost of this we expect to be three weeks of lost production. The actual repair costs we think will be maybe quite a bit under $1 million. The main loss here will be three months of production, which could be in the neighborhood of $7 million. It's quite an expensive cost from that point of view. We also expect that on the return to production, that we'll see a recovery of that 30% of lost production. In fact, we're hopeful that it could be even more. The payout on this turnaround we think could be quite quick and allow us to generate all of the oil we need to meet our future sales obligations as well as to pay out the costs of lost production in maybe as little as three months. But we're estimating in three to six months that we will be able to pay out that cost. The planned turnaround in May of next year will go ahead anyways, in spite of us being able to do a lot of the things that will be done for that turnaround, because there are critical parts, especially in the gas plant, compressors, et cetera, that have regulatory and engineering time limitations and will have timed out by then. Those are very long lead items that are planned to arrive in first quarter of next year for the turnaround in second quarter of next year. This turnaround will be an extra turnaround. As I said, we think it will pay out before we get to the next turnaround. That's next slide, Jason. Yeah. In Quebec, this continues. We were seeing this in other countries like Germany and countries in Europe that had very aggressive climate policies, and I don't think that the province of Quebec is backing away from its view that climate policy's important, that emissions reduction is still important. But we are seeing a clear, unequivocal change that any transition is going to take a lot longer. The key report that came out prepared by the Quebec government to inventory its energy supply, and this exercise was taken under a new law requiring the Quebec government to create an inventory of its energy supply relative to demand every year to make sure it doesn't run into a crisis like it did a couple of years ago on not being able to supply new industry that was looking to locate to Quebec. Unfortunately, wasn't able to secure long-term electricity contracts because of the electricity supply problem in Quebec. This report has now come out and said that natural gas is a strategic part of the energy supply and will be for a long time. They did not speak to local gas specifically, but I can say that really the only argument that has been presented against moving forward with local gas, in spite of its substantial global emissions reduction compared to importing gas, was that Quebec had a very short-term need for it. The projections were all that Quebec would be fully transitioned off of natural gas by 2030. It's now clear that the plan to transition is going to be slow and gradual, and that has really eliminated the last and only main reason other than, I guess there might be some NIMBY, not in my backyard objections. There's no strategic objection to local gas once Quebec has acknowledged that it will need it for the foreseeable future, which it now has. So this is an ongoing progression of the change in political and macroeconomic situation in Quebec, as is happening in other places in the world, and we think very favorable for our project. The election is in October, and we don't expect. Other than that there was a public announcement by the existing government that looking again, not saying that Quebec should or shouldn't, but saying that Quebec should look again at the use of local gas, was a public announcement by this government. So there'd be nothing that will happen on this. As we're already in August, the elections unofficially has already started. Officially starts in the last week of August, and will result in a new government in the middle of October. There's speculation as whether the new government will be a minority government or a majority government. In either case, we expect that the government will have to address, or at least look at addressing the energy shortages in Quebec. The other thing I would say is that because we've already had 30 wells drilled, 16 wells drilled on our acreage, these wells are suspended. They've been tested. They're ready to produce. So we have a project that we can be in production very quickly. Really the main constraint will be regulatory and government approvals on the basis that it was allowed to go forward. So in terms of major projects or major projects in Canada, we think our project is the one that could deliver jobs faster than any alternatives. Okay, next slide, Jason. Okay, so just in terms of the near-term outlook, what's our goal at PX? The main goal here is to commercialize billions of barrels for Questerre. The oil shales around the world contain trillions of barrels. If conventional resources like we see in the North Sea, like we see in shale gas and shale oil in North America, all measured in the billions of barrels. Oil shale is a resource that is measured in the trillions of barrels. The challenge, of course, has been nobody has really found a way to efficiently refine it. We think our approach, which instead of using a mining solution of continuously processing rock like you would do in most mines, we have instead come up with a process that refines solid rock with organic material in it. Instead of basically using very similar ideas as are used in refining of liquid crude oil, we are using very similar principles to refine a solid rock. We think it makes the process 50% more efficient, both from a capital point of view, much simpler to build these drums without a lot of moving parts in them, and also much lower operating costs. We expect 50% lower costs and something that will commercialize a resource that is an order of magnitude bigger than existing conventional resources. We are excited that we have been able to show that this platform has already been able to save us tens of millions of dollars in testing costs. For Quebec, we continue to advocate. We are true believers that local gas is a significant environmental benefit, that local tomatoes have less trucking and less emissions than imported tomatoes. The same is true for gas. If you produce it locally, you save all of the transmission and processing costs. We estimate 1.7 megatons of emissions reduction per year by going ahead with it. Of course, it is a significant economic and benefit as well as a strategic energy benefit for the economy of Quebec. It is on Tidewater, so very well-positioned to be able to export that gas, whether liquefied natural gas or as we saw when the Strait of Hormuz closed, gas is also a strategic resource for making fertilizer and other products. There are lots of ways for that gas to get exported to international markets. We continue to advance the legal action, but our priority is to reach a business and political solution with the government of Quebec that should they decide that they want a strategic solution to the energy crisis in Quebec, we would like to be there to help provide that. Next slide, Jason. I think we are at the end here. Yeah. The rest is warning you that investing in stocks is very risky. You can lose money. Recognize that a lot of things we are telling you is forward-oriented information. With that, hopefully that was reasonably clear along with the materials that we released. Our plan is to continue to have this a standard practice for us every quarter or for every financial release, regular financial release. Maybe now, Jason, if you want to see if there is any comments or questions that we can try to address. Yeah. We have a couple questions. I'll maybe start with the one that most of the investors have. Just give me one second. One of the questions relates to the acquisition of PX Energy, and it is when we bought PX Energy, the oil price was much lower. When do you expect to see a recovery in the cash flow and production of PX? Related to that is, will we be looking for a new partner for PX Energy? Right. Okay. The first point, I guess, to understand is that historically, PX has not made money. They did have some years with positive EBITDA, but negative net income. When we took it over, it was about break even. As I mentioned, the principal consideration we gave for buying the asset was to assume the debts that the company had accumulated. But we were taking over an operation that, let's just call it, was negative cash flow, break even to maybe slightly positive EBITDA. In terms of the turnaround of the asset, we think we've made dramatic progress and much faster than we had originally planned. We certainly expected that by the end of the first year, so let's say by the end of this year, that we would've seen the turnaround delivering the results. In fact, we started to see those results in the first quarter of this year with the positive EBITDA of, consolidated was about CAD 20 million, but we were maybe CAD 13 or so million in PX. I guess to answer your question, as we say, that we think we're already seeing a significant turnaround in the cash flow, and we're probably ahead of what our original plan was for that. I think delivering a second quarter, in spite of the deteriorating production at the plant of positive cash flow, again, is showing that the cost reductions that we've been able to implement and that we continue to implement are delivering sustainable results as opposed to one-time results. I think that's part one answer to the question. Now, we're hoping to take this from, we're in Canadian dollars now, but let's call it CAD 15 million or so a quarter. We're hoping to take that to something like maybe up towards $30 million a year. I guess that would be seven. Well, it's not far off what we're doing now then. We're hoping to take it up to $30 million+ per year of EBITDA cash flow from PX, which means we need to sustain what we have now, even at lower oil prices. To do that, we need to increase our volumes. We expect that the plant turnaround will show that we can bring our volumes up by 30% or more, hopefully in Q4, compared to Q2 and Q3. Q1 and Q2 have been a lot constrained by, we had a lot of demand destruction from customers. In Q3, we're seeing that come back. Both the distributors are lifting their minimums and in fact are asking for more than their minimums. Right now we can't deliver it due to the plant turnaround, but we expect that that demand destruction that we saw in Q1 and Q2 was partly permanent, but largely temporary as people were running down inventories, hoping for a quick reduction in the prices. We also are seeing new customer opportunities. The one that we're most excited about is the opportunity. The oil that we produce, which we market against heavy fuel oil in Brazil, is in fact, on a specifications basis, a marine gas oil in terms of its viscosity and flashpoint viscosity. It's more of a marine gas oil. Its sulfur is too high, a bit over 1%, to sell directly into international markets for marine gas oil. But we are working now on blending with lower sulfur marine gas oils, and other local markets in Latin America with different sulfur restrictions. We're hopeful that we can develop a premium market for our product, as I said, as a marine gas oil, and expand our demand. If we're to look at that, the second part of the question is that even with, let's call it back to $70 Brent, we think we can continue to deliver these kinds of cash flows by having higher volumes and increasing our market. What was oh, partner. Okay, final part of that question was partners. We had looked for a partner to help us with the CapEx and exposure on this asset. We've already taken that exposure, and we've been able to absorb it. As I said, the cash flow turned around a lot faster than we had planned. I think in one sense, we just don't need the partner for that purpose anymore. The other benefits in terms of local market access, we've now established relationships that we didn't have before with major distributors, we have Vibra and Rodwell, our existing distributors. We've been making inroads with Petrobras, who is a supplier to us and a purchaser of our naphtha. But we've been talking to them about marine gas oil, which they have some interest in. We're trying to hit Ipiranga, which is another $20 million-$25 million, a billion-dollar US company. We're also looking at the South part of Brazil. We're also now looking at markets in Uruguay and Paraguay with new customer relationships, distributor relationships. Both Uruguay and Paraguay are closer to our plant than some places in Mato Grosso do Sul or Northern São Paulo from a trucking point of view. I think we're finding that we've been able to develop some of those relationships ourselves in a fairly short period of time. Also we like the idea now that we're not tied to one distributor, which we would have been under the original plan. We think it's actually worked out quite well for us that we now have multiple distributors that we're developing relationships with as opposed to one. I think the answer is we're now looking for partnerships rather than a comprehensive basis on a project-by-project basis. We're looking at a partnership for fertilizer and limestone, which we co-mine with the shale and would make a material difference to our operating costs. We're looking at separate partnerships in the marine gas oil, and I think we'll continue. We're also looking at condensate opportunities, gasoline opportunities. These different opportunities we're all looking at with different entities and on a project-by-project basis as opposed to a partnership on the overall asset. I think the end answer to the question is we're not looking for a partner to be 50/50 on the overall operation anymore. We are looking for strategic partners on specific projects and product lines. Okay. There were a couple of questions just relating to the break-even pricing. Can you give some indication of what the underlying cash break-even price would be at sort of normalized oil prices? Yeah. If we could speak to both normalized prices and volumes, and this is something that we've learned the hard way is that our fixed costs are largely, our costs, I mean, our overall costs of operating the plant are largely fixed, and so we don't see a big difference in monthly costs at 10,000 tons of fuel oil per month versus 13,000 tons of fuel oil per month. And so critical to the operation is this increase in markets and volume. Because the extra 3,000 tons ends up being mostly all profit because the variable costs are so low. So at normalized prices and volumes, our target had been able to bring operating costs down to $45 a barrel. I think we achieved in the first quarter based on some of the volumes, something close to $55 a barrel in some months. We're still targeting the $45 a barrel as a break-even cost with let's call it $70 Brent, and let's call it 12,500 tons, 13,000 tons a month in volumes. Hopefully that answers the question. The key point being is that the $45 is dependent not as much on pricing as it is on volumes. We've just got one more question on Brazil, just relating to the turnaround. What do we expect the cost to be for this shutdown that's underway right now, and also the lack of production beyond the CAD 1 million that you mentioned for the repair? Yes. So just to mention, we're anticipating three weeks of lost production, which on a revenue basis would be, let's call it on our minimum sales, about $7 million, and we're expecting less than $1 million of direct costs. We're about halfway through the turnaround. There's still inspections going on. It's not impossible that there could be surprises that would cause it to go longer or to cost more money, but at least to this point, there have been no material surprises having got 50% through the turnaround. The short answer to the question is we're budgeting that the plant turnaround cost, both from direct costs and loss of business or revenue would be about $8 million. As I said, we think out of the extra production that we can pay that out in three to six months. The next questions are relating to Quebec. Just wondering what the milestones are for the next 12 months for shareholders to look for, and then also what's being done to preserve the value of the asset in Quebec as we wait for the legal process to move forward. Specifically, have we seen any feedback from other parties on local gas production in Quebec? Yes. So that's a multi-point question. Let's see if I can unpack those. In terms of preserving the value, we continue to have a responsibility for the physical assets, the wells. We have a permanent person on contract. We do regular inspections of the wells. We maintain security over them, and we maintain certainly responsibility in spite of contested ownership. In terms of the physical assets, we continue to maintain them and have continued to maintain them, and those costs are sitting in the operating costs of Questerre. So that sits in the results that we've released to you. So that answers that narrow question. Relative to the preservation of the overall asset, the gas in the ground, that is maintaining our legal position that the government bill, certainly as enacted, did not have constitutional authority to cancel our contracts indirectly or in a de facto way expropriate our discovery without fair market value consideration. That is what our legal claim is about, that should the government decide to change its mind about its contracts, that it has an obligation to compensate people on a fair market value basis, and our lawsuit is to protect that on behalf of our shareholders. As far as milestones go, we are finding that the big issue now is that we had a breakthrough in terms of the overall time by, one, allowing Questerre's case and also Utica Resources, a private company in a similar situation to us, that we have been allowed to go forward as a demonstration case called a test case, but it is actually to demonstrate the legal principles. Any other claimants will stand to the side in suspension, and their cases will depend on whatever happens in our case. That has a significant benefit of having the overall hearing be much faster, because we will not have close to 10 different claimants, all with slightly different fact cases, and more importantly, all with different ability to see the case through. We think that will overall speed up the overall hearing quite a bit. The other part of that is it will hear both the merits of the case and also damages in one hearing, something that will also overall speed things up. But in the short term, it has caused a delay because while Questerre had done the work in advance on a damages report, which has been done on the basis not really of damages, but of the economic loss that our shareholders suffered through the purported cancellation of the contracts, and we have had that ready for two years. Neither Utica Resources nor the government had prepared an official third-party expert opinion on their economic losses, or in the case of the government, windfall gains. They are now in the process of doing that. We expect, in terms of milestones, to hopefully see this expert opinion report from Utica Resources before the end of this year. The government is suggesting that it is going to take them longer to do theirs. We have a case management hearing in November that will settle the deadline for the government to have its expert opinion report done, as well as addressing a series of objections that the government has made to our questioning of key witnesses like ministers, where they are claiming cabinet confidentiality and cabinet privilege for some of the testimony. We do not think that the cabinet privilege or confidentiality applies to all of those questions, so the justice will rule on those issues as well. Getting to milestones, I would say the expert opinion reports is one milestone. The case management decisions on objections to witnesses' testimony is another milestone. But I think relative to our real goal, just to sort of switch, that our real goal is to have a political and business solution. We think the value to our shareholders, and frankly, the value to Quebec of the asset being developed is orders of magnitude bigger than the value in the expert opinion. Just to remind people, our expert opinion shows a low value of CAD 700 million. So do the math on that compared to the number of 40-some million preferred shares outstanding. So even a low value would give quite a good return to our preferred shareholders. It has a high value of CAD 4.8 billion, which is what the expert opinion, expert witness, or our expert says is the best value case or the most valid value case is the CAD 4.8 billion. We think that the value under development is much higher. So we are working to get that result if we can. As I said, we think that result is a much better result for the people of Quebec, both from an environmental, economic, and energy security point of view. Okay. We have one final question just regarding the HCCO test at the Petrosix refinery. What results would we need to see before we would consider the technology commercially proven for implementation? Yeah. Well, we are just updating that now. There is another test that was announced earlier around. We have been talking to people about how the existing Petrosix technology has an issue with agglomeration, which is basically that the shale, over time, starts to smear and agglomerate and create blockages inside the retort for the rock to move, and ultimately can sometimes lead to uneven heat flow inside the retort. This is an ongoing issue and a normal issue in the operation of the Petrosix technology. But if you operate the plant outside of its specifications, agglomeration can get worse. That is exactly one of the things that happened in the last plant turnaround that we are now finding as we get into the very minutia of it, that it was operated outside of spec several times. This resulted in a few different problems that has ultimately led to this extra shutdown. We did a test in the 2 ft by 12 ft that showed that the processing of the shale on a static basis virtually eliminates, not completely eliminates, this agglomeration problem. That was a key technology risk that was dealt with a test that we spent about CAD 1.5 million - CAD 2 million on last year. That was a significant breakthrough from an engineering point of view on Technology Ready Level. This one, to be able to test the working gas Homogeneous Charge and Continuous Oxidation parameters in a full-sized vessel was another, I think, big technical breakthrough. We are in the process of having Hatch, a worldwide engineering company, update our Technology Ready Level. We think we have addressed two, if not the main two technology risks that were identified before. We think it is going to make a material difference. What I can say, will that allow us to go straight to a full-sized twinning of the retort in Brazil without the need to do a one-tenth scale pilot? I am not sure about that yet, but it is possible. What we do plan as a next step is we will buy the equipment to be able to operate the HCCO process inside the Petrosix retort on a continuous basis and on a commercial basis. We anticipate to get that done within the next 12 months. This will depend in part on bureaucracy and regulatory approvals in Brazil. We cannot promise that timeline, but that is our goal, subject to those parameters and regulatory parameters. We will then have a continuous operation showing that the HCCO process is working, not in the optimal retort design, but nonetheless, in a continuous way that, 24/7. We expect it to operate with a relatively quick payout in terms of the extra thermal efficiency that we will bring to the old technology. I guess the answer to the question is, one, we are updating the Technology Ready Level with external independent engineers. We are planning to implement the process in a, not our optimized design, but in a 40, 50-year-old design, to show that it can operate continuously. I think that will be a major commercial step. I think that hopefully that is a good answer to that question. I will tell you though, from a financial point of view, from an investor point of view, I think the implementation of the process on a continuous commercial basis that allows us to make more cash flow at PX is a very significant milestone. I can tell you for the engineers, these last two tests are breakthrough tests. Okay. I think that's it for the investor questions that we've received. Okay. Well, I guess we'll close off now. I wouldn't mind if there's feedback you guys want to give to us directly or through whatever forums on whether this call is useful, if people have suggestions for improvement. I think we've already made the commitment that we'll continue it. But if people have suggestions for improvement, we are happy to take those. This was our first time as a quarterly update. And happy to hear your feedback, and thank you for your time and attention today.