There is no insurance policy, which we will continue to see here, as we have one of the biggest, if not the biggest supply shocks that's ever been seen in the market. Of course, the main topic at hand is the Iran-Hormuz crisis from February to April of 2026. It began on the night of February 28th here in North America. We are currently at 53 days of supply disruption, and even though there's been a lot of conjecture and propaganda you can say about each side winning and what they're saying, at the end of the day, the strait is still blocked. There is still multi-millions of barrels per day offline. 20% of global supply is at risk, and is currently at risk as we speak, as well as very little tanker traffic through the Strait of Hormuz. We hit $117, which was a seven-week high since this conflict started, almost approaching the 2022 levels when there was not even that much of a supply disruption. We have a $98 Brent monthly average for March, which is the highest in about four years, that we're seeing here. A big boom for E&P producers that are trying to get as many barrels out as possible. For those that are new to these presentations, we will do a bit of a look back. The U.S. and Israel launched Operation Epic Fury on February 28th, strikes on Iran's military and nuclear sites, and Supreme Leader Khamenei was killed during an attack on his house. Iran retaliates across the region. They close the Strait of Hormuz, and the tanker traffic dropped to zero, something that was likely unexpected, at least not to this level, by everybody involved. We saw the oil spike intraday there to $119, followed with a naval blockade, certain negotiation talks that have now stalled, no resolution in sight. Then since then, it's just been a bunch of back and forth, but nothing really has happened. We see today oil back up to $93 on the WTI. Especially today as we've rolled over to the June contract, which is now trading another month further out. Will be interesting to see how that trades as the week goes on. Now over the last couple of days, we've had a reclosure of the Hormuz Strait after the U.S. has refused to lift its blockade, including three attacks on ships last night by the Iranian people there. Good rebound on WTI. Volatility is going to be the new regime, especially with the introduction of paper markets and all the trading that's going on, all the amounts of people involved, the amounts of tweets that are being shared. A new regime, if you will, of volatility, not of resolution here currently as we speak. At the same time, U.S. shale is peaking and has peaked. This is something that was identified in late 2025 with the amount of M&A activity that was happening in the Permian, in the Eagle Ford, in the Bakken. You saw companies get bigger and bigger, get more resilient, but also more disciplined. They were no longer willing to go out and just put out rigs for the sake of growing. They are making more money today from their existing base going up in price as opposed to the growth. Management compensation metrics have changed. You've had differences in inventory degradation. You've had not as many private equity-backed companies out there. You can see that we are down from the U.S. production peak that was hit in 2025. The average Permian breakeven continues to go up due to this aforementioned inventory degradation. Also due to increased water handling cost, increased gas processing requirements, increased gas takeaway required, and just naturally degrading wells that are not producing as much as they did. The Tier One inventories have been depleting. The operators have been moving to Tier Two and Three outside of Lee, Eddy, Reeves, Midland, and Martin counties. At the same time, the Bakken and the Eagle Ford are in structural decline. They have been declining for many, many months now. With frac spreads at also multi-year lows, and water/oil ratios rising as well. We expect to see that despite this new change, we don't expect to see producers add rigs. We expect them to have incredible capital discipline, which can be seen, because even at a very high oil price environment over the last seven weeks, the Permian has added a net of zero rigs. Then the Bakken has actually declined further. Companies are happy with just keeping their cash flows higher as opposed to using the production metric as sort of their make or break. What is really important about this is that the world has counted on U.S. shale growth, that every time the price spikes, that U.S. can add 1 MMbpd, no, 1 MMbpd, per year of shale growth, and that just is not going to happen. This was very, very important for the market to see with the amount of lull that people have gone into this sort of structural undersupply market with. This becomes more and more and more proven, it will result in a naturally higher market going forward, with that barrel being priced where it actually should be, not based on the tweet or the whims of somebody that would just like to crush it in the short term for severe and major long-term gain. Let's get some data into this. As to what I'm saying, you can see on the left side is the drilled but uncompleted well count. These are the wells that have been drilled but not fracked yet by U.S. companies. You can see we were at about 14,000 in 2020. We're now below about 6,000, about 7,000 there. Almost one year's worth of wells that were drilled have been brought extra to the market by this phenomenon of these drilled but uncompleted wells that were sitting around. At this point, the wells we have remaining are one of two categories. One, completely bust wells that are not worth fracking and putting the money into fracs, where the well bore has gone outside of the zone, or they've hit a water zone, or the zone has collapsed. Or the second reason is that this is an operational inventory. When you have one rig drilling a six-well pad, usually you don't want to be fracking on the same pad, resulting in frac hits and sort of disruption, safety risk. This is your natural operating inventory, as that rig works its way through that pad. You can see another insurance policy of the world that we have continued to remove from the market as time has gone on, and is showing no signs of returning at this point. At the same time, you can see the middle graph is your frac spreads, which is the number of active fracking crews that are out there. You can see it has been cut right in half over the past, roughly four years. You're seeing less and less companies that are interested in going out and fracking. Yes, there is simul-frac, trimul-frac, with one frac spread able to do multiple wells at the same time. Yes, but it doesn't account for the sheer 50% drop that we've had in the number of operating frac spreads here over the last four years. You can see there really isn't any spike here happening, even though we're seven weeks into this. As companies add frac spreads, they know it will still take about 8-16 months for that well to really come online, and be producing and for them to ramp up. They're unwilling to do that while the world is pushing for lower oil in the meantime, despite the reality of the lost barrels that are happening as we speak. You can see on the right side, the U.S. horizontal rig count. Again, a steady declining number on every single basin in the U.S. There isn't something that has come out of nowhere and suddenly has started to grow. Any basin that has added rigs is so small and minuscule that it is barely making any dent in total U.S. oil production. You can see here the Texas side of the Permian and the New Mexico side of the Permian are declining heavily, along with the Eagle Ford, which is the bottom green line as well, continuing to go down. This is not just a Permian phenomenon. This is an across the basin, across the U.S. maturing industry that is resulting in more capital discipline and just less focus on growth here. At the same time, we have evaporated our supply buffer. On the left side, you see here the U.S. SPR, which was released by the previous administration from about 650,000 bbl to all the way down to about 350,000 bbl, a massive release that was done in 2022, and 2023 in order to protect the global markets and have the U.S. step in. Yes, they've done that. We had about 40-60 million bbl added over the last 18 months from the U.S., but not enough. They are now draining this again at a rate of about 4 million bbl a week, which is set to accelerate as the world needs the U.S. barrel here going forward. Expect to see this hit again, a 40+ year low here, potentially the lowest that we've ever seen back when data tracking first started in about 1981, 1982 here. Really the SPR is supposed to be used in these types of time frames. Yes, the Strategic Petroleum Reserve, but it also is only a one-time use in the sense that that barrel, once it's gone, is gone unless you refill it, which was not done anywhere near the pace that should have been, over the last few years, going into a conflict of this nature. On the right side, you have commodities on water. So kerosene and jet fuel that's sitting on the water. You can see in a relatively healthy band, it stays. Why? Because ships have to travel. It takes them sometimes multiple weeks to take the oil or the product and reach the destination that they're wanting to. You can see here we had a rollover that was already happening, going into the January-February range, and then wham. It's just gone completely, almost off the chart here, as we continue to see these barrels arrive, but no new ones shipped. Why that's important is because when you're buying that barrel now today, by the time it gets loaded and gets to you, it's going to be two months. There's a supply lag here where people are going to have to be scrambling to find these barrels because the boats just kept coming after the conflict started. Now that the final boat is set to arrive, now there's a complete lag. No boats to be found for two months. Going to be very interesting to see how the spot market reacts. Going to be very interesting to see how the products market reacts here, over the next few weeks. We are into about that 60-day mark of the conflict, is when things start to get really tight on the physical market. As you can see, that's where the SPR comes in, but nowhere enough to meet the global requirement here today. This is a Vortexa graph of all observed oil in tanks and tankers. It includes floating storage, includes oil on water. It includes onshore crude inventories, includes SPRs. You can see here the five-year range shown on the right, or, sorry, on the left side here, you can see that COVID ramp that happened in 2020, with the barrels going up at a pretty decent clip there. You can see in 2025, we did have a structural oversupply. Barrels were rising globally inventory-wise. The interesting thing here is, even though OPEC+ was releasing more and more barrels as the year went on, you can see the inventory line actually start to normalize, which means that the OPEC+ barrels were just being taken over by increased global demand from all the increased demand that happens when you artificially keep the price low, and then wham, now we have this steady downward. The interesting thing here is the slope of this downward curve is about the same as the slope as we saw upwards when COVID happened. This is definitely a black swan event. Again, lots of interesting things to watch here. Very, very dynamic market and with some dislocations happening with oil on water dropping quite a bit. Chinese inventory is relatively flat. North American inventory, but European products starting to drop. Asian products starting to drop. Then as that permeates through the market, you will see that impact in North American and Chinese inventories, which are sort of your last buffer that remains of excess barrels available. Which leads us to Canadian oil. We are the safe haven. It's been insulated from the Hormuz. We are connected to global markets, both through the West Coast of Canada and also through the Gulf Coast of the U.S. Of course, the TMX export pipeline giving us global markets, 0% exposure to Hormuz, and a very tight WCS differential. Because we've lost barrels in Iraq, the heavy oil barrels, and there is no real natural replacement, you're starting to see that the WCS diff for the first time in forever has started to stay tight despite WTI prices rising. That refiner is still willing to pay for that barrel as we go, which is a very good place to be. At the same time, the US dollar has been quite strong, which means that the Canadian dollar has been weak, so the end dollar per barrel on a Canadian dollar basis is some of the highest that we've ever seen by a significant margin. [This] makes us in a fantastic place, especially with companies like Prospera that are looking to grow in this environment while taking advantage of the increased cash flows from our existing production base. Low decline, low risk, capital-efficient assets. We do not run any type of drilling. We have a reactivation strategy, which we will discuss this as we go. In short, the investment thesis. Supply is structurally broken. We have demand that is extremely resilient, especially as the emerging markets hit their S-curve. There is no buffer. We have the SPR at 40-year lows, continuing to drop. We have the buffer of the oil and water now already drained. We have the price floor rising of what price is required and for what timeframe before the producer is willing to add barrels. Canada being the safe haven because of the zero exposure to the Strait of Hormuz, the access to global markets through the West Coast, and the extremely tight WCS differential with the weaker Canadian dollar giving us exceptional pricing. With that, I'm going to pass it on to our board member, Dr. Christopher Moore, to share a few thoughts here. Yeah. Thanks, Shubham, and welcome to all of our investors who are on the call today. Before I dive into the data, I just want to give everybody a sense of where I'm coming from and who I am. My name's Dr. Chris Moore. I am a professional dentist in healthcare, and I own and operate a dental practice in Ontario. You can appreciate in my world, precision isn't just a luxury, it's a requirement. If my math is off by a millimeter, it makes a difference and the procedure fails. For the last several years, I've tried to apply the same lens to the energy sector. As an independent board member for Prospera, I tend not to look at energy through the eyes of Wall Street analysts staring at a Bloomberg terminal. What I try to do is I look at it as a bit of a practitioner in the physical market. I spend a lot of my time bridging the gap between high-level macroeconomic cycles and the ground-level engineering required to pull these molecules out of the ground. A lot of what I have to say actually mimics what is kind of repeating what Shubham has to say here, but I'll add just a couple little twists. I'll be the first to tell you I've been in this story for over three years, and for a long time, I was early. In this business, when you're early, it can feel like you are actually wrong. When you're watching the paper market, that is completely detached from the physical reality. I watched the world pretend that shale was infinite, that the energy transition would happen without heavy molecules. I didn't join this board or deploy my capital into Prospera for a speculative flip. I invested personally because I saw the mathematical inevitability of where we are today. I just didn't know when it was going to happen. I saw the assets that this company has, 400 million bbl OOIP, and that it was being priced at a fraction of its replacement cost. I stayed in this story for the last three years because I knew the molecular squeeze was coming. Just didn't know when or where, and here we are. As Shubham has said, I was aware that the U.S. shale treadmill was running out of steam, but I invested because I wanted my wealth to be anchored in to a physically producing molecule, if you will, in a safe jurisdiction. Here we are in Canada. Finally today, the world is catching up to the reality that I have been living for the last 36 months. It's been hard being early. Really, we are standing at a hinge in history, really. This time that we're living through mirrors phase one of the 1973 oil embargo. In 1973, it took exactly 30, 40 days for the world to realize that all this oil on water, the tankers that were in transit before the declaration of the Arab countries for the oil embargo, had run dry. We're at that exact same cliff right now, here in late April. It's just that most of the world has their eyes closed. We hear a lot in the media about what's going on. A lot of it isn't necessarily accurate. The Hormuz blockade has physically severed 13% of the global supply, and the last Iraqi heavy oil tankers that were loaded before the March escalation have finished offloading in the U.S. Gulf Coast, and behind them, the pipe's empty. Why should investors care? We sort of say, because while the media talks about prices, behind the scenes, if you're not part of the industry, you won't notice that the physical market is absolutely screaming molecular starvation. You have North America and China. They are the world's refining fortresses, and these multi-billion-dollar refining plants are designed for one specific diet, and that's heavy sour crude. You can't run a commercial trucking fleet or keep the food grid moving on light oil alone that you get from the U.S. It will end up crashing the distillation yields from the refiners. When those heavy molecules disappear, the physics of the global economy break, and that's kind of where we are right now. We are moving into a period where the person holding the physical molecule, specifically heavy oil, has leverage over the person who has the printing press, right? And you sort of say, "Okay, well, how did we get here? All this time, how did we get here?" Well, we spent the last decade lulled into a sense of security by, as Shubham was saying, the short cycle shale miracle. Let's face it, US shale satiated 118% of global demand growth for the last 10-15 years. As we're now finding out, it was a mask, and it masked the fact that we have starved the world's conventional fields of $2 billion a day in capital maintenance for the last 10 years. Again, as Shubham mentioned, shale has a dark secret, and that's the decline curve. Shale wells decline 30%-70% their first year, so it becomes a treadmill. To feed it, the industry has basically lived off a savings account of DUCs, pre-drilled wells, drilled uncompleted wells. When I take a look at it today, the account is essentially empty, and the Permian is rolling over, and at the same time, we've cannibalized our SPR for, in some cases, political points. We've essentially sold off our insurance policy during a peacetime, leaving us with zero safety, a zero safety net, just as the global supply is severed. We engineered this crisis through a decade of capital starvation. For your money, I guess, my message to investors is, for your money, this means that the old rules are broken. If we take a retro study of the 1968 to 1984 period of time, which this period of time definitely does rhyme with. In 1973, he ended up raising rates to 20% by the early 1980s, and it worked because the debt-to-GDP ratio was pretty negligible. Today, the world is sitting under a $300 trillion global debt canopy. Here's the thing, and this is what I'll ask everybody to kind of consider, is that we are going to be potentially in a QE paradox. Think about this. If the central banks hike rates at 15% to kill the energy-driven inflation, they're going to trigger a systemic sovereign default. They will essentially break the world to save the currency, but the alternative is just as lethal. If they print money to save the banks, and that liquidity flows directly into the one thing that the world is starving for, i.e., the physical molecule, it's going to drive the cost of that physical molecule up. When you consider the fact that from an investor standpoint, our paper wealth is we're essentially caught in a pincer movement, and the question is, which way do we go? The U.S. dollar is no longer backed by full faith and credit. It's backed by the ability to secure that energy. Now we're moving to an era where the only metric really that's going to matter is having the purchasing power in a high inflation vacuum. When I talk to investors, they say, "Okay, well, what does that mean for me? Where's the opportunity?" From my perspective, the opportunity is in the physical pivot. For 20 years, the smartest money has been in the paper market in oil. It's been on the futures curves. The paper market is 50 times the size of the physical market. I believe strongly that the next 5-10 years is going to be in the area where those producing the physical molecule will end up making substantial profit. We are rotating out of the cloud, per se, I guess, and back into the crust, if you could put an acronym to it. From my opinion, the opportunity lies in the short cycle, heavy oil assets in safe jurisdictions. Why? Because the world cannot, and I repeat, cannot wait 10, 15, and now 20-22 years for deepwater projects to come on. There's just no possibility. We need the barrels yesterday, and this crisis is going to make that very obvious. This is where the sovereign restocking floor is going to come in, that even if the ceasefire is signed tomorrow, global SPRs are at terminal bottoms. Sovereign nations, China, India, the U.S., will be forced to outbid retail consumers for years just to rebuild their national security buffers. This restocking is going to create potentially a permanent structural floor. The winners won't be those who print the money, but those who produce the energy. That's where the value in what we do at Prospera lies. I guess I would encourage investors to understand that the time for theories has ended. The 30-day logistics fuse has burnt out. We're standing on the edge of a cliff, and over the next two-three weeks, things are going to get very, very, very real. We're now entering the phase of the crisis where the gap between the haves and have-nots is going to be determined by who owns the molecules and the pipe. As an investor, as someone who's heavily involved in Prospera, I've been early to the story for three years because I chose to believe the engineering over the headlines. I choose to invest in a company that doesn't just talk about energy, but we are physically delivering that to the world. The world needs our heavy oil. Quite frankly, the wealth transfer from the digital world to the physical world is, I believe, going to be the trade of the decade. We'll see whether or not that weathers the future, but that's what I believe. When I'm talking to investors, I encourage them not to wait for the mainstream media to tell them that the crisis hit is here. It's here. It's just that the world still has their eyes closed. I would encourage people just to keep their eye on that. Okay. Back to you, Shubham. Yeah. Thank you there, Dr. Chris. Just a reminder for everybody on the Twitter Space, if you would like to join us for the Zoom slides, the link is in our latest news release or in our website as well. You can join us for the rest of the slides here as we go. Now we will have our CFO, Chris Ludtke, speak about the financial performance over the Q1 period and over the, especially the very interesting March 2026 period. Thanks, Shubham. Thanks, Dr. Chris. Certainly, some interesting topics here presented for discussion this morning. Quite insightful and quite bullish looking forward here. What I want to start with talking about with Prospera really is, as Shubham mentioned, the focus on Q1 financials, but more importantly, March. Commodity pricing environment escalated considerably in March. We'll talk about some of the prices on the next slide. First, for the company, revenue of CAD 1.96 million was realized in the month of March, and that's a 68% increase over February. It's our strongest month since May of last year. This was driven almost entirely by commodity pricing, and I'll walk through some of the mechanics on what that looks like on the next slide. A netback, secondly, of $40 per BOE was realized in the month, and that's the best unit economics we've posted in 12 months. A dramatic improvement over the numbers that we saw in February and January. Thirdly, field operating netback of CAD 872,000 was realized in the period. That single month nearly matched our entire Q1 year to date, which tells you how much the quarter's performance was concentrated in March. Let me take a minute here to walk you through what happened there. This slide shows how we walk through WTI benchmark to our realized Canadian dollar revenue. Every month, we go through a process of looking at what the monthly calendar closing amount was for WTI, taking into consideration the WTI to WCS differential, and then walking that right through to a WCS Canadian dollar barrel, which is really the price marker for Prospera's barrels that we sell. Starting on the left, WTI closed at $91 U.S. per barrel. That's up significantly from the low 60s that we saw in January and February. The WTI to WCS differential narrowed to just $12 in the month, and that's hugely important because a tighter differential means more benchmark prices flows through to our heavy oil revenue, and that gives us a WCS at $79 USD per barrel. Now, we've had a strong US Canadian dollar, which Shubham mentioned earlier on in the presentation. Converting that US WCS price lands at approximately CAD 107 per barrel, which is nearly 60% above February's CAD 67, CAD 68. This is the first time that I've seen a high WTI price combined with a narrow WTI to WCS differential, combined with a high US dollar. It really is a bit of a perfect storm here for the Canadian heavy oil producer, and the revenue that's being realized since February 28th. We've seen in the early 2000s, we've seen high WTI pricing, but that was coupled with a fairly large or fairly wide WCS differential of $30-$40. This is the first time that the Canadian producer has seen prices that are actually this attractive. This slide speaks to the financial performance of the company. On the left, you can see the consolidated P&L. March revenue came in at $1.96 million, which I mentioned earlier, against total costs of just over $1 million. That includes royalties, OpEx, and transportation when I talk about total costs, delivering the net operations of $872,000. For context, Q1 year-to-date net operations sitting at about $1.12 million, meaning March alone contributed about 78% of the quarter's total. On the right side, the unit economics also tell a fairly compelling story. Revenue per BOE jumped to $91 in March from under $60 in February. What I'd really draw your attention to is the OpEx line, $38 per BOE in March, down from $42 in February, and well below the full year 2025 average of $41. That cost discipline is structural and not just a one-month event. Our focus is strict financial discipline through the remainder of the year, regardless of prices increasing. We need to make sure that we manage our costs as best we can. Focus on the controllables, the production and the cost. Those are the engines that we can control. Prospera is relatively unhedged at this point in time, so able to take full advantage of the high commodity pricing environment. Can you move on to the next slide, Shubham? This is where we break out the performance at the CGU level. It's critical for understanding where the value is being created, where these physical barrels are coming from, and the assets that are associated with them. The chart on the left ranks our assets by netback per BOE. Every one of our three core operating CGUs is generating positive netbacks. We are seeing the Red Earth property generating higher netbacks, and this is a predominantly light oil property that benefited hugely from the higher commodity price environment. At only a smaller portion of their revenue, the combined revenue, it's a small contributor. Cuthbert in Saskatchewan is the engine, the cash flow generating engine, $27 per BOE netback, 300 bbl a day and a very low royalty rate, approximately 7%. That combination makes Cuthbert one of our more capital efficient assets, contributing to the monthly cash flow. Luseland is the growth asset and currently producing 243 bbl a day at almost $17 per BOE. Solid economics. This is the CGU that we see the most upside in. We've talked about this in past conference calls. We've identified over 140 reactivation targets at Luseland. As we bring those wells online through 2026, this is the CGU that has the potential to meaningfully grow our production base, without the cost of drilling new wells. Very capital efficient asset. Heart's Hill rounds out the portfolio at just under $10 per BOE, positive but lower margin. However, the big picture, Cuthbert and Luseland together represent about 72% of our total production and 80% of the net operations. Our capital allocation strategy reflects that concentration. This slide, we're proud of our blended operating cost came in at $35 per BOE for Q1, and that's a 15% reduction from the full year average of 2025. It's not just about spreading volumes across fixed costs. We've been actively managing the controllable line items. The table on the left shows our top five operating costs, contract operator, surface lease rentals, and property taxes are the largest fixed costs that we focus on reducing through our multi-year fixed cost reduction strategy. This is another reason that the Luseland reactivation program is so important. Electricity came in at approximately $4. We've seen some benefit from lower natural gas prices flowing through power costs. This is something to point out here is we've seen oil pricing increase considerably, but gas prices have remained fairly constant. As a result, a lot of our energy usage on site has been controlled, and so we've seen electricity stay relatively flat. The donut on the right gives you the visual breakdown. The key takeaway is that the contract operator fees, surface lease rentals, property taxes represent over 35% of total OpEx, and those are the biggest levers we have for further cost optimization. This is a slide that was put together previously and really is meant to demonstrate some of the sensitivity around quarterly capital investment versus free funds flow. The organization is in the process of deploying capital to bring on additional production here through the year. We've run some sensitivities on what that price looks like or what the free funds flow looks like at various different WTI sensitivities. We still maintain a fairly conservative outlook on pricing. However, as I mentioned before, we are in a position to be able to take advantage of the higher commodities as Prospera is relatively unhedged. We have a small portion of our hedge that's focused on WTI, but we're also able to enter into some WTI to WCS differential hedging around the $12.50 mark, which we expect to benefit us throughout the year and we feel is a good choice to make. I'll wrap up with the key messages. First, revenue strength. March was exceptional at almost $2 million. The WCS surge delivered a $40 netback, our best in over a year. Second, price sensitivity. We have to be transparent about this. January and February averaged much lower dollars per BOE in our netbacks. Our results are highly leveraged to commodity pricing, and investors should understand the volatility that cuts both ways. Thirdly, Cuthbert is a significant cash flow engine, continues to be reliable and efficient, generating higher netbacks, lower royalties, and a considerable portion of our production. We'll see continuous focus on maintaining that field on a go-forward basis. Luseland. Luseland is the expansion property. This is the growth story. We have 140 identified reactivation targets of Luseland, currently producing almost 250 bbl a day. This CGU has significant running room. There's significant reserves here, and reactivations are very capital efficient. We're bringing existing wells back online rather than drilling new ones, and economics are very attractive at current pricing. OpEx discipline, $35 per BOE blended cost is down 15% YoY. However, we would like to see it get into the sub-$30. This is not a one-quarter anomaly. We expect to add additional volumes, which will continue to reduce the fixed cost per BOE, and we've been systematically reducing costs, and that trend continues. The production outlook, we do expect to add additional production through the year as we execute on service rig programs going forward, and we'll have more information on what that looks like going forward with focus on Luseland ramp-up and Cuthbert stability. Shubham, I think that those were most of the slides or the pieces I had to talk about. Happy to pass it back over to you for wrap up. Yeah. Thank you, Chris. I appreciate that update. Very exciting month for us. There's no question that in a sub $60 oil environment, in January and February were tough months. We had to be resilient and get through that time. I can highlight two things here. One is with a 62% increase in average selling price between March and February, the netback per barrel actually jumps 8x, and therein lies the beauty of a sort of higher cost, but smaller growth producer is we are able to take advantage of the higher oil pricing, not just to generate exceptional netbacks that immensely increase cash flows, but then take that same cash flow and be able to put it in the ground and able to maintain and grow our barrels at a much faster pace than we would be able to do in those tougher months there. The other thing I would point out there is the operating cost piece, is as we scale down these operating costs, every single dollar saved is effectively the same as higher WTI pricing by a dollar. As we get through this timeframe, we move forward on our growth profile for the spring and summer of 2026. Expect to see a more resilient company at lower pricing, but also that cash flow torque is going to continue to rise, as we're able to put dollars into the ground, add barrels, and also just reduce operating costs in general through reduction of property tax, reduction of well sites that we'll be reclaiming, getting removal of surface costs, and just more and more efficiency as we go. With that, we're going to pause it here for a brief Q&A. We'll pass it to Sean here for this brief Q&A. Following that, we will have a technical discussion on the Key Wells Report, talking about some of the best wells we brought online in Luseland, and why we're very excited for this 2026 program, as we continue on. With that, Sean, can you please ask any questions that have been asked by the investors thus far? Yeah, you bet. Thanks, Shubham. Just a reminder, even as we move into the technical session, you can continue to submit questions. Excuse me. We only have about three here. First one, how do you identify reactivation targets? Yeah, I can take that one. When we as a new management and board came in in October of 2024, we had this strategy to prove. We began with a blend of wells that were higher impact wells, but came with a bit more risk of sending in versus the reliable producers that could make 6, 8, 10 bbl per day. You will see in our Key Wells Report, not every well is absolutely rockstar mooning. There is other wells that are just steady 6, 8, 10 bbl per day producers. That is by design. We want wells that can run for many years with very little operating babysitting required and can just chug out cash flow week after week, month after month. We did a blend of these wells as we grew the production base back to where it needed to. Now that we've hit a multi-year, eight-year high in the Luseland property, our next program is going to consist of a lot more of these high impact wells. Most interestingly, we've been able to dial in that strategy. This is not as simple as, "Oh, yeah, we're going to go in and do this exact same mechanism." Yes, it is repeatable. Yes, it is predictable. We've iterated that strategy as we've gone on, to just be better and better, more suited towards higher barrels, more suited towards better sand cleanup, and just better netback. For example, if you have a well that can make 10 bbl per day and stay online for multi years without going down, versus that well could do 50 bbl per day, but require a workover every six months. Those are the types of questions we're asking ourselves constantly. Some of these wells that have been down for 15, 20 years will create a huge sand vortex right up front that we need to effectively manage. As that well cleans up, you start to see us able to speed up the well, and the oil cuts of the well go up as that water is removed from that borehole as well. We've got a pretty dialed in engineering plus geologic strategy to pick these wells. In a lot of cases, we are working multi months ahead of the rig. That doesn't mean that the rig schedule is set in stone. We still go back and iterate based on new knowledge we're receiving from the wells that are currently online and from the wells that were brought online in 2025. As we play around with those wells, we make slight adjustments. The wells behave a certain way, and we use those learnings to change our strategies on the following wells that will be started up here after the spring break-up season of 2026. That's happening right now. There is significant engineering analysis. There is significant field operations learnings. You blend the two together and you get an idea of what needs to be done. At the same time, we are adapting as we go. When those wells give us some new data that we haven't received before, like the fluid level changing all of a sudden or the sand cut changing all of a sudden, we act immediately and make the necessary requirements, changes that are required in order to keep the well online without needing a rig and in order to continue to maximize that production as we go. This is a constant exercise daily. It is not a set it and forget it type of model. This is exactly the production engineering skill that the Prospera team has which is lacking in the industry or has gotten lost as the entire industry has moved to unconventional shale rock fracking, and sort of that focus on that well-by-well heavy oil optimization has been lost. We still have a lot to learn. We still have a lot to go here. That will continue to adapt and iterate the strategy as we go over the next few months here. Thanks, Shubham. This is actually a good follow-up. Next one is, are you able to get a good sense of payback timelines before you initiate a reactivation? Yeah. In a lot of cases, yes, we are able to get a good idea of the payback timeline, especially if the well just continues to run and we're able to actively manage that sand influx up front. There are certain cases where the well will go down and will need to be bailed out with a service rig in order to proceed again, which adds a little bit to the cost of that well upfront. At the end of the day, we have relatively decent knowledge about the payback periods, the timelines on it. Of course, commodity price dependent, so we run different types of sensitivities on it, and then actively monitor that on a day by day, week by week basis as to how many times payout that the well has received. One of the points I do want to make to investors is a lot of these wells have been, because they've been down for 15-20 years, the surface equipment is gone. It's not just that the well needs a sand clean out or a new pump. The engine is gone, the 750-barrel tank is gone, et cetera. When we first do a reactivation, we need to pay for that equipment. The well needs to physically make oil and netback and profit to pay back the cost of that engine or that tank. That's only once. Once you have that paid for, that's a 20-30-year long equipment life type of equipment, that doesn't need to get paid back over and over and over. What I'm trying to say is, once the well has paid back its downhole cost plus the surface equipment once, we calculate the second payback as just the downhole cost. Because you're not just going to keep paying back the engine over and over and over. Its lifespan is a lot longer than that first payback. When we talk about the well paying back second, third, fourth, fifth time, those are happening at very, very quick intervals. I'm pleased to share that we have a very strong AI integration going on, developing exceptional dashboards within the corporation, and hopefully have some investor access to this in the near future as we continue to our path of ruthless transparency. We will be continuing to share stuff through my personal LinkedIn and the Prospera LinkedIn about the profitability, the paybacks, the timelines per well. Investors that aren't following us on both LinkedIn and Twitter for sure have a look there, because we share way more information there, and of course, through these conference calls as we build our company here in 2026 and beyond. Shubham, I'd also maybe add here a little bit as well, because just to make it clear to the investors that are listening, when we look at a payback analysis on reactivation, a lot of the times the fixed costs are already covered. The surface costs or any of the property taxes associated with these wells, they've already been paid. The operators are already visiting a lot of these wells. Although, yes, they have to go back a little bit more frequently. When we look at the payback analysis, in a $90 price environment, yes, the royalties ramp, on a percentage basis, along with the revenue increases, but the costs don't. We're seeing, largely from a payout standpoint, only variable costs associated with these paybacks. For example, when we look at it, we're seeing, okay, $38 operating cost per BOE. That's not the cost that an incremental well is incurring on a go-forward basis. When we look at a payback analysis, it's roughly about $15 of variable OpEx plus the $5 associated transportation that's taken into consideration. If we see a $40 netback when we look at March financials, the variable netback on a new reactivation well is actually more like $60. Slightly less than that because we're not having to take into consideration the additional fixed costs. I just wanted to make that clear for listeners out there, and that equates to a much earlier payback than if we were fully borne by the full amount of operating costs on the fixed side. Thanks, Chris. Next question. Is the plan to deploy all recent increased cash flow into reactivations, and how quickly can this be deployed? Is Q1, Q2 fully booked for reactivations from the $3 million raised? Yeah, I can take that one to begin, and then Chris, if you had any thoughts. We expect to run, as was previously news released, a two-service rig program here right after spring break-up. For those that are living in Calgary or in Saskatchewan, you know how the weather has been. Three inches of snow plus, and then all of a sudden plus 15, which is not good for that spring break-up thaw to come out of the ground, and allow us to run the rigs. Some of the counties still have road bans in their areas. Right after this process ends, we expect to deploy quite aggressively, into this type of profile while being measured, watching commodity pricing, ensuring that we're not overspending based on the amount of cash flow that's coming in every month, and just having a very nice measured profile there. I remind investors that our current barrels are already recognizing a massive increase in netback, from what we have. We have to run a more measured pace as opposed to just blowing money and then having lots of payables on the books that the pace of cash flow cannot match. We expect to be, though very, very nimble. We have pre-ordered parts already, including recycle pumps that have arrived on site, including certain engines that have arrived on site, additional engines on order. We also maintain an inventory of 750-barrel tanks, along with certain kind of valves and also some 1,000-barrel tanks that sit at some of our boneyards. We are ready to proceed, not to be impacted by shipping shortages or anything stuck. We moved very quickly in February, and March, and April to find alternative sources of critical pumps, such as the recycle pumps, such as the chemical pumps, some kinds of check valves and ball valves as well. We are well set here, to expand from here on out, and sort of deploy all that capital along with the increased cash flow. At the same time, the corporation is focused on continuing to clean up our balance sheet, through strategic deals and finding ways to work with our vendors here, going forward on these programs. Chris, did you have any thoughts? I would echo that, Shubham. This is a measured approach. We've been working closely with vendors to make sure that they're ready to go. We've worked diligently to make sure that there's credit capability, that we've got excess and spare inventory to be able to execute the plan. At the same time, we still need to live within our cash flow. Yes, there's more cash flow, but we still need to live within that. Break-up's taking longer this year than it normally would. I think we're probably looking sometime towards the end of the month to be able to really get going. Next question is: How has the weather seasonality impacted production compared to last year? Yeah, there has been very little impact from the weather this year. The winter was relatively mild in terms of overall production impact. The boys out there in the field did a fantastic job at keeping the insulation done, keeping the heat trace lines running. This was money that the corporation chose to spend in the fall timeframe. We had a lot of questions asking why our operating costs in the Q4 timeframe last year were quite high, and that's part of the reason. These assets have been mismanaged, and sort of under loved for many, many years. We had to come in, we had to do things the right way, fix up roads, add insulations, add different kinds of heat trace, fix up engines, hydraulic pumps, heat trace pumps. Really, a lot of that has paid off its weight in gold. The Luseland graph is the one that I would refer investors to, given that Luseland has the heaviest oil. It's got some of the most wind in that area because of the flatness of the area, and also the fact that you're having very low water cut wells. They don't have that push of the water, to be able to move that oil. That oil is already at 5,000-8,000 centipoise. It becomes very viscous when it's on surface. We were able to keep these wells going very strongly, along with keeping the recycle pump lines and the chemical pump lines going. Not much impact this year. We expect there to not be much impact here going forward. We'll be having an even more disciplined approach here going into the late summer, early fall, for next year. We'll just continue to make these assets more and more resilient. We need cash flow reliability as a corporation in order to proceed on the projects that we do. We cannot have huge failures due to winter and blizzarding conditions, et cetera. There are some days when, yes, one or two wells do go down, and because of the aforementioned ability where Prospera has acquired our own pressure trucks, our own steamers, and our own equipment, we're able to get those wells on very fast, and at a very low cost to us because we're not paying for travel time, we're not paying for mileage, and we're not waiting for that equipment to go service another company before they come to Prospera sites. Very proud of the team out there, in the field that we have currently. They've been working non-stop day in, day out, and we expect to just continue to build here and have further and further reliability here, going forward. That's great. Thank you. This one's a little bit forward-looking, but I'll throw it out here. What is your expected OpEx and barrels in, say, one year? If you want to touch on that. Yeah. Prospera does not put out any type of forward-looking guidance. What I can say is we have 40 wells that we have identified as Tier One reactivation candidates that we would like to address and get back online this year. Along with that, the existing Luseland wells that we have continue to be optimized and barrels added. Investors can clearly see this in the transparent Key Wells Report that we put out. We put out that report for many reasons, but especially to show that the existing wells continue to produce more and more barrels. To highlight Chris's point earlier about the variable netback, when that well goes from making 22 bbl a day to 26 bbl a day, the variable netback on that, or the variable operating cost on that is actually like $7 a barrel because the well is already online, everybody's already going there, the burner's active, et cetera. As that well rises, it creates exceptionally high netback barrels, even at lower oil pricing. There's sort of a triple whammy effect on those. As far as the operating costs go, I will echo again, Chris's thoughts. We would like to be sub-$30 per barrel here on the operating cost portion of the company stack here. Also backstopped by our contract over the summertime to sell directly to a asphalt user, which results in incremental netback as well in that Q2, Q3 timeframe. A few things working in our favor here as we continue to ramp. The company also has an extensive reclamation plan that is expected to commence at some point this year, which can result in about $600,000 a year reduction in operating cost by the removal of suspended sites, and the removal of expenses due to property tax, surface cost, and the weed spraying expense on those sites, which we are not seeing any potential in, going forward. Can you please explain why it is Canadian heavy oil is leveraged to upside in pricing going forward? I can take this one, Shubham, if you want. It's almost essentially a math exercise. Let's take a scenario where you have a light oil company. Light oil is not as expensive to get out of the ground. Let's say, for example, you have a situation where oil goes from $70 to $90, $20 increase. If you have a light company, let's say hypothetically, their operating costs are $50 to get out of the ground. At $70 oil, they're making $20. If the price goes up by $20, that light oil company is happy because essentially their profit doubles. If you take a heavy oil company that has operating expenses, which are maybe, let's say, hypothetically $69. For every $70 barrel that they sell, they make $1 profit. If oil prices go up $20 from $70 to $90, their profit is not doubling. They are now getting, instead of $1 profit, they now get $21 of profit. You would assume in an efficient market that their stock is trading according to their profit. The light oil, you would expect the stock price would go up 100%. The heavy oil company, because it's so levered to price, you would expect that the stock would reflect a 21x. All right. That's why when we take a look at the crisis that we're in right now, compared to the crisis back in the 1970s, there are certain things that are very similar. Running up to the crisis, we had a severe under-investment in oil and gas. The oil embargo was the match that lit the fire. There was a failure of an energy master plan. Everything was going to go nuclear. Everything was going to be produced by coal and nuclear energy. There was a massive monetary debasement because President Nixon took the OECD world off of the gold standard, and there was a lack of spare capacity. The U.S. was the spare capacity swing producer at the time. Their production was rolling over. We see all five of those things in today's cycle, and if you take a look at the Canadian heavy oil companies between 1973, after that match was struck from the oil embargo, with proper pricing into 1980, Canadian junior heavy oil companies went up 30x. In answer to your question, when we get proper pricing, we are leveraged up. We are also leveraged down. The last two years have been very painful. I, as a board member, have watched Chris and Shubham and our ops team work under an environment of scarcity. Fabulous production as a team, working together, making sure that we have a managed expense ratio. When it goes up, heavy oil companies really have an advantage. Thank you, Dr. Chris. I think we'll do one more. Just a reminder, I know a bunch came flooding in here, but Shubham and Chris's contact are on the slide there, so feel free to reach out. Last one: At what point would reducing exposure to commodity pricing through derivatives enter the picture at Prospera? I can take this one here. I think we're always looking at our hedging strategy. We're always looking at what the optimal hedging is. When a company enters into any hedge strategy, they can't hedge all their barrels. Typically, they can hedge up to 50%, 60%. There's a counterparty credit risk consideration that comes into play, that needs to be taken into consideration from the third-party side as well. That being said, though, we're comfortable continuing to increase our barrels and continuing to hedge more of those barrels in a higher commodity price environment. We want to be able to avoid any sort of downturn. A $55 a barrel WTI price hurts the company badly, right? We all feel that. We want to avoid those outcomes and those situations as much as possible, and look at hedging in the $80, $90, $100 barrel price environment on a go-forward basis. It does require additional production, and it's not just a management decision that we actually throw that out to the board and look at that across multiple different disciplines to be able to enter into that strategy. Shubham, any more thoughts there? Yeah, I think there's a couple of things here that are very important for investors to know. As Chris mentioned, number one, companies don't have the ability to hedge all their barrels. That simply doesn't exist. Especially for smaller companies that have more fluctuations in pricing, or sorry, more fluctuations in production, it's an even bigger sell. We have built strong relationships across not just our current hedging counterparty, but across additional hedging counterparties in order to really see where that market is, and find that best sort of scenario where we have access to that. The other one I will mention, if you, as a commodity producer, are hedging the physical barrel, some of you might be in other Canadian E&P names that have hedged a huge portion of their production. You are still forced to pay royalties on the actual pricing of the market. Let's say you've hedged 100% of your production at $60 a barrel. You will still pay royalties at $91 a barrel in March, which puts significant constraint, and sort of terrible cash flow, on certain companies that are overexposed to hedging. It goes both ways. It's not as simple as, "Oh, it's just downside protection." There is additional context to have in mind there. The third piece that I will mention is the financial market paper hedging is an extremely dangerous game because you are basically playing with margin. You're playing with sort of money that the bank is giving you as opposed to your own barrels. For a small company like us, just doesn't have the ability. Because if you had, let's say like what happened in COVID, if you have, let's say, one day where the price runs up to $500 a barrel and closes there, the company would be responsible for that delta between the hedge paper, financial derivative, and that actual closing price, and could possibly take the company under, even a one-day scenario. We will never be in the paper derivatives game. I think that is a very dangerous game for a producer of our size. I think on the physical market, we will be very cautious about what we hedge. The differential hedge that we have put in is wildly in the money, at $12.40 a barrel differential. Those are the kinds of risk/reward skews that we'll play. WCS differential can go as low as $9, $8, maybe. If there was a big issue, it can blow out to $40-$50. You can see the skew there. We're able to protect $40 worth of cash flow per barrel by giving up at max about a $3 upside. The company was very prudent at that time, put that hedge at about 300 bbl a day. 40%-50% of our production, 30%-40% of our production, we'll say, was protected there. We'll look forward to these kinds of risk/reward scenarios. You will not see us become completely reliant on the markets. There's actually no way to protect yourself 100%, as I mentioned. Even if you put in a floor of 80, let's say, for the next two years, and then the prices ramp to 500, for whatever reason, you're responsible for the royalties on that number and could actually become a huge detriment to the corporation. It's important to keep additional factors in mind, especially as somebody, as Dr. Chris mentioned, producing the physical barrel is a lot different than trading the barrel on the market. Partly why some of these oil traders make billions of dollars a year because they have that sophistication and capacity to run these types of models and risk profiles. Thanks, guys. I think we'll leave it there for the Q&A session. Yeah. Pass it back to you, Shubham. Right on. Thank you, Sean. All investors that would like to contact us for further questions can reach out at these emails here. Anybody that's in Calgary, we are also interested in meeting with. We will now move on to the Key Wells Report section of the presentation, following which there will be another Q&A, in case there's any technical folks here in the room and/or just general questions as well. One of the things that the company is moving forward to is energy education. As part of that, we will be talking in depth about each of these wells as the year goes on. For those that are familiar with our LinkedIn Prospera account, you may have seen some of the two to three minute clips that Sean has put together, microcontent we call it, as a way to explain a bit more about the wells in detail. We will continue to do that going forward. Very excitingly, investors can see now, over the next couple of months, each of the wells on the Key Wells Report will have a link to that clip, allowing investors to really understand those wells in detail, not just from a business standpoint, but actually from a technical standpoint. Many petroleum engineers work at the company, after all. This is the Operations Tracker and Key Wells Report that was put on the website as of early this week. This is our latest version, the April 2026. It will be updated on a monthly basis. For investors that are new to the story or new listeners, this is available on our website at the bottom of the homepage, and you can freely preview this at your own time. Really what we would like to talk about is Luseland. This is the growth engine of the company. This is the biggest OOIP, Original Oil in Place. This is the biggest production possibility and the biggest reserves here as we continue to grow out this pool. Very exciting to prove out the strategy of reactivating wells that have been down for over 20 years as part of our 2025 plan, and now looking to scale that in 2026. I vividly remember operating wells similar to this and asking, "Why aren't these wells online?" "Oh, well, management doesn't want to do it," or, "We don't have the capital," or, "The payback periods are too long at $40 oil," which is when I was operating some of these wells in 2016, 2017, 2018. We are proud to report a 378% growth in 17 months through these reactivations, optimizations of the current wells, and active sand management. Sand is something that has to be produced. You cannot leave it downhole. It will severely restrict the ability of that well to produce. As mentioned, we have 41 more that were identified as Tier One candidates. We have already brought one of those wells online this year, so we have 40 to go, and we have about a 2%-5% recovery factor across the pool. We are just at the beginning stages. I remind investors, some of these wells were online for over 40 years adjacent to another well that's been down for 20 years and is still making 10-12 bbl per day, and we expect will continue for another 20-40 years. When we talk about the scope of 17 months in our hyper fast, hyper pace world today, it is just a blip in time as we continue to prove out the strategy. We are of the firm belief that a company that has low decline, reliable, optimizable barrels will trade at higher cash flow multiples in a bull market as opposed to a super high decline, running out of inventory type shale play that has been the norm over the last 10-12 years. A few pictures here from our site as well. The senior management team and the C-suite of Prospera is often in the field, meeting investors, meeting field operators, spending time out there looking at optimizations. Most of the engineers on our team have field experience and are able to also assist, in this manner, as well as develop strong relationships with the local vendors and some of the local landowners, who we're very, very proud to work with, stalwarts of the community in these areas. There's also a production overview that comes as part of this. We share the production from every pool on a monthly basis, along with the revenues per month, as was shared earlier by Chris, in the presentation. We will continue to update this here for the April amounts as soon as the April final lease operating statements are confirmed in the next couple of days. Oh sorry, March is already in. The April statements will be confirmed in May, couple weeks of May. You can see the production area. Production by area graph, we started off slow, ramped up throughout last year with strong capital deployment. Kept the pool relatively stable there at those periods of time. We saw a dip in February with the lower cash flows impacting our ability to really work on the wells, keep production fully maintained, and now we've been able to ramp back up here, to our 2026 highs with expectations to continue to rise on the base barrels, but also the two service rig program that will be beginning right after spring break-up, as is currently planned. I should also share with investors that certain wells that were producing oil but were not making money in a $60 oil environment were turned off in the December to February timeframe as a way to protect the cash flow of the corporation and give up some barrels. This is something that we will now reverse as we go right after spring break-up, allowing for easy barrels to come online that are now cash flow positive at $90 oil, that weren't cash flow positive at $60 oil. Some of you may have noticed this trend over the last couple of months with production coming down, and part of this is the reason that should be openly shared as an iterative process that the company continues to do on a weekly basis, at our weekly production meetings and at our weekly corporate management meetings as well. We'll talk about some key wells here. We have our star well, the 10-07 well. This is a model of consistency. You can see the way that the well has just consistently performed. We did slow it down a little bit in the November and then the January timeframe. Consistently 24-26 bbl per day. It then went down in mid-February, and we were wondering why. It was producing very nicely. The water cut was looking very stable. We didn't pull on it too hard. Once we did the workover, we realized that the pump with the water and the sand in it was creating an erosional wear right above the pump. The three-four joints above the pump were getting severely worn down because of that high velocity that we were putting through that area. What we did, we reduced the pump from a 30 series pump to a 20 series pump. You can see we're running it at lower RPM, but we're getting the same oil at higher oil cuts. Even though we're producing less total fluid, we're getting the same oil volume, resulting in less disposal required, less processing of that water required, and the same oil barrels per day. You can see how this is a technical change that was made. Rather than pull on the well harder, we said slow it down, make the highest barrels we can out of it. We can see here now, almost approaching 7,000 bbl per day since reactivation. Or sorry, 7,000 bbl total cumulative production since reactivation with a Q1 revenue exceeding $100,000, and we expect that Q2 will exceed $200,000 per quarter because of that downtime that we suffered in Q1. I remind investors, we can bring these wells online for about $150,000 each. When your quarterly revenues are starting to be over that and the super high netbacks on these wells, as Chris mentioned earlier, we're starting to get really excited at these oil prices, about these kinds of wells. I will remind investors, this was done with a geologic analysis. We found half a meter of water at the bottom of this zone, and so we are not interested in speeding this well up without reason, because the water will cone up in this fashion and affect the oil production of the well. Being very reasonable, very measured, we're happy with the production here. The 10-08 well is our optimization success story. I spoke before about the well going from 20 to 22 to 24, and that's exactly what the 10-08 well shows. We have not even sped this well up in the recent timeframe, but the oil barrels continue to go up. Why? Because of the oil cut. As we're producing that water out of the reservoir that has settled into your wormhole over the last 15-20 years, the oil cut starts to rise, that matrix starts to flow a lot easier, and we're able to produce these wells at the same RPM but with way higher oil production. For investors that didn't listen to our last calls, we explained the technical information around wormholes, sand matrix, and propagation in the March and the February conference call, which I suggest investors look at as a way to add some context to what I'm saying today. On this well, we continue to see higher sand cuts. As we produce that sand, the well seems to hold a really, really solid fluid level here. We're excited to see where this well can go. We have not even optimized this well currently. As we produce the rest of the pool, this well produces too high of a percentage of our total Luseland production for us to really work on optimizing it too much. We're leaving it as is. We're going to go and activate more wells and then come back to this one once it becomes a smaller portion of our total Luseland barrels, allowing us that ability to work through a potential sand-in event as we continue to optimize the well in a bit more aggressive manner later on this summer. 1017, our up-dip star performer. This well sits on the up-dip edge of this pool with a shale barrier on the northeast corner of the Luseland pool. Very low water cut. Very high oil cut. It has production legacy of 400,000 bbl already, and we expect it to have another 20-40 year life here. Very low sand production. We haven't even gone to the phase of trying to initiate wormhole propagation here. We are just producing 10 to 12 to 15 bbl a day that just rolls into the well every single day. At some point, we will install a recycle pump here, start to get that sand moving, and try to initiate sand influx, which can result in new parts of the matrix starting to produce. Again, Q1 revenue, almost $100,000 per quarter. We're very happy with that on these kinds of reliable wells. The up and down pattern you see here is the variability of the well as it takes on very, very small burst of sand. Because this has such a high cumulative oil production already, the sand usually doesn't come in huge influxes unless we initiate that propagation. We're seeing that as those small pumps of sand come in, we keep the reservoir clean, and the well is easily able to manage those. One of the key things I will mention on these wells, we are not spending money on any type of flushby. We are not spending money on any type of load oil. The wells are running not at their max capacity. They're running somewhere between 40%-60% of their max capacity. You ask why? Because we don't want to spend day after day money trying to keep the well going. We don't want the well to sand in and then have to spend $27,000-$40,000 on a rig job. We want to, at current time, produce reliably, sustainably, and then as we run the rigs throughout the summer, add additional wells, we then have more ability to push these wells a little bit harder, because losing one or two wells for a period of time is not going to destroy the entire corporate profile, given how important these wells are. One of the more stable wells that I mentioned, the one making 6, 8, 10 bbl per day, the 12-017. I'm exceptionally happy with this one. It's got a newly installed recycle pump on it. There's a small hot oil program as well that we're looking to initiate. One of the wells that's not going to be a high impact well. This is going to be your steady performer. It will not decline for many years. It will give you that consistent barrels per day, allowing us to have strong cash flow reliability as we continue to grow our Luseland pool here. Slightly lower revenue, you see that? Still very high netback, and it will just continue to pay out over and over as the pool here continues to expand and as time continues to go on. We will be able to bring this up to this 10-bbl-per-day range as opposed to this current 4-6 bbl-per-day range that it currently sits in. 16-007, our top producer today, about 28 bbl per day. It did hit a high of almost 36 bbl per day in that April timeframe. 20-year shut-in produced very high water cut for almost 60-90 days, started to ramp up, and now it's steady, sitting at a Q1 revenue of over CAD 150,000. We expect that to continue to rise here as we further clean up the well. This well has an enhanced recycle pump set up on it with higher volumes being injected, more sand being brought up, and just continue to optimize this as we go. We would like to show investors as we go in the summertime, new highs on not just the pool as a whole, but individual wells hitting numbers that some of the newly drilled wells in the basin are producing at a cost of millions of dollars that we can bring online for about $150,000 each and have them have way more longevity with a lower decline rate than those newly drilled wells that decline at a very strong profile. 3-009, one of my personal favorite wells. This is one that we continue to just let her chug. We pushed it a bit hard in August. One of the ideas that we had was to do a well load, which did not really work as what we thought. It proved that the well had the capacity to produce way higher. The total reactivation cost on this well was $118,000. The Q1 revenue was $125,000. Just showing you the exceptional return profiles on these wells. Some of the highest and most stable production rates in the field. We have now increased the pump actually through a 13 series, 1,500-meter lift CHOPS pump, and we expect that this well will continue to rise here as we go. We are being slightly cautious with this well. There's a video of this well on our Prospera LinkedIn as well that got really good traction, and this is a well here that is just continuing to produce, continuing to add more barrels, and one that when it went down in about that 1999 timeframe, was making 191 bbl per day of oil. We are still at a fraction of where these wells were when they initially went down. We have better technology, we have better focus, and we have way higher oil pricing than the companies did back then. I'm very excited to see how that foreshadowing translates to reality as the rest of 2026 continues. Another stable, steady eddy well, the 11-018. You can see here we went through an initial sand phase that caused the well to lose a barrel or two a day, and now we're starting to see this well ramp up again, going back up to that 9 or 10 bbl per day range. Again, we have to be very cautious with these wells. We cannot push them how we want to all the time. These wells are not even as viscous as honey. They're more viscous than the way that honey flows out of a container. It takes a long time for the reservoir to actually stabilize and get to a stable producing rate. It's not as simple as taking one or two days of data and saying, "Oh, yeah, let's go and make this change and go and make that change." We have to be very careful, which we love doing. We're nerds about this well-by-well strategy, and we expect it to continually get better as we go, leading to just higher barrels and higher cash flow, as we continue here. 7-033, one that gave us a lot of lessons. The Section 33 is in an area with only 2%-3% of the oil in the ground recovered. Incredible sand influx that's happening. We were able to successfully prove the well producing for about five months very stably, and then wham. As soon as we fell below five joints of fluid in the casing, we just could not handle the sand influx. We tried really hard to keep this well going. We were able to produce barrels, but at the end of the day, despite daily monitoring, daily optimization, we were not able to rebuild that fluid level to where we needed to in order to keep the well running in a stable manner. We decided we're going to take the hit, go in, did a $30,000-$35,000 rig job, and now are working through that sand influx phase. We're keeping about eight to 10 joints of fluid now on the well, and the strategy here is going to be increase the recycle rate. At the same time, speed up your pump. That allows you to produce more and more sand while not allowing the reservoir to slough in. As that sand cut starts to come down and we know that the sand is not building in the cellar or in the wellbore, we can then increase the well without increasing the recycle, thereby bringing this well to new highs. You can see the high there was about 22 bbl per day. I would want to see a number way higher than that this summer from this well, but we have to be patient, and we have to be measured as we go through this. 15-04, steady Eddie, another one. I again want to point out to investors, not every well is going to be 24, 26, 30 bbl per day. We will have steady wells that we will keep at a very low rate, relatively very low rate of 8-10 bbl per day and just let them chug there, until we can go back to them at a future point in time and really push them harder, and see what they can really do. 16-08, one that we're really working on. This well was not actually down for 20 years. It was making about 3-4 bbl a day for 20 years. So we've gone back here, we've installed a recycle pump, and we're going to just slowly produce this well at the same rate while bringing more and more barrels up. What I mean by that, over the last 20 years, the well was only making 3-5 bbl per day oil, and it was making 0.5% sand, 1% sand. We're injecting 18-20 bbl per day, and the reservoir is giving us 4-5 bbl per day. A total of 23 barrels per day making 1.5%-2% sand. We're able to 5x the amount of volume of sand that's coming up the tubing while actually only producing the same level of reservoir oil. As we clean up that near wellbore area and produce that sand, at some point, we're going to be able to go back in and really increase the speed of the pump, thereby producing a lot more reservoir oil. At this point, despite the well being online for about nine months, 10 months, it's still not possible. Why? Because over that 20 years of low-rate production, there is so much sand that's accumulated at the perfs, at the wellbore, at the near wellbore, in the cellar, that we are just having to be patient. Reminder, some of the areas in this pool are 10 meters thick, 14 meters thick. You can imagine a 14-meter thick sand column that falls down into your near wellbore area and how long that would take to produce. A usual floor in a Calgary downtown office is about 2-2.5 meters. So five stories of sand, bam, falling in. It takes time to produce this. One of our sort of hidden gems here, and we don't really mark it. We just leave it as is. Let her chug. At some point in time, I will be sitting here on a conference call saying, "Okay, 16-08 is now ready to rock." A few months later, I will be saying, "16-08 is up to X barrels per day and has successfully proven out the thesis that can then be put into some of our Tier two and Tier three wells, that are currently lower down the list. But if we can successfully prove this, also would become Tier one candidates." 4-33, another test of patience here. We're having to be very slow with this well. There is not only a large sand influx phase here, but there's also some edge and bottom water going on here. So we're unable to really push the well too hard at the expense of coning the well. But you can see back in July, it was doing 26 bbl per day. We know the well can produce. It just needs to be slowly managed as that sand and water are very carefully managed. It's definitely university-level education and patience that the team and our investor base is currently going through with further hidden upside as we continue to produce these wells slowly and steadily. 4-17, this is the top well in the area in terms of legacy cumulative barrels, 750,000 bbl over the course of 44 years. You can see a consistent, reliable 10-11 bbl per day. When we go and say these wells will have zero decline or almost negative decline for many years, and can produce for multi-decades. We mean it, and we have the receipts to show it. We will continue to show transparently to the market and to the investor base why we are so proud of this Luseland Pools, and why we're so excited to continue to ramp this up here as we continue to go on. A 750,000 bbl is one of the top producing vertical wells in Saskatchewan. One of the statistics that I love to share, of all the wells in Saskatchewan that have made over 500,000 bbl of oil vertically at less than 50% water cut, there's only 10 that have ever done that in Saskatchewan. We, as tiny Prospera, own four of those in our Luseland property, and with additional wells that can hit those same metrics if properly produced here over the next months and years to come. Very exciting. With that, I will wrap this up. The Key Wells Report is available to investors on our website at the bottom of the homepage. It will be updated on a monthly basis. We also have a refreshed corporate presentation that will be coming out as well. The recording of this Twitter Space and the YouTube, and the Zoom will be available as well through the Twitter and the YouTube platforms. With that, I appreciate everybody's time here joining us. Sean, if there's any final questions, we can have them here. Otherwise, we have the investors' email here, and we also will again bring up the slide of my and our CFO Chris Ludtke's email for anybody that has any personal questions. Always open to discussions, whether technical or business, and we're always interested in very interesting strategic investor alignment as well, as we continue to scale our operations in this higher commodity price environment. Yeah. Thanks, Shubham. No more questions came in. I would just add also on the website we have a bit of a library on these monthly webinars, so you can also review our past ones as well. Appreciate everybody taking time today. Thanks so much.