Buccaneer Energy plc. ($BUCE)

Good afternoon, and welcome to the Buccaneer Energy Investor Presentation. Today, we are joined by Chief Executive Officer, Paul Welch. Questions are encouraged throughout this webinar and can be submitted via the Q&A box situated on the panel on the right-hand side of your screen. I will now hand over to Paul to begin the presentation.

Thank you very much, Ivy. Thanks for joining us, everyone. Good afternoon. I'm going to take the next 20 minutes and kind of give you an update as to where we are with Buccaneer, and for those that are new to the story, a little bit of background about Buccaneer's assets. If we could go to the next slide, and then 1 more. Thanks very much. So Buccaneer Energy has been around for quite some time. It was founded in 2005, and we are currently focused on U.S. onshore conventional production. We've got assets in the 3 areas, East Texas, West Texas and South Texas. We're going to focus today on our discussion about our East Texas assets. West Texas is just a single asset is producing quite well for a long time. And then our South Texas asset is something that we are actively trying to sell. And given the current price environment, we do see some people that are interested in that. So that one will go, we think, relatively quickly. I came on board almost 2 years ago now. And at that time, we undertook kind of a revamp of the business. We did a series of workovers to essentially expand our base production, and that was successful. We essentially improved our profitability and doubled our production. As a result of that, everything that we could be producing within the asset base is now producing. And so now we've moved on to some growth initiatives, acquiring offset production in the Carlyle One, to talk about more detail coming up. And then we're doing 2 enhanced recovery schemes and oil recovery in time mills. And we have a pilot project that we've just completed, and we're looking to implement our waterflood in the Fouke area, which is a combination of what Carlyle One acquisition was about and then the expansion of the production in the Fouke area, and we'll talk -- I'll talk more about that in upcoming slides. That is, again, in progress, and we expect to start producing there towards the third quarter of this year. So next slide. So quick summary of our initiatives here. We're seeing increasing cash flow and reserves. So our cash flows have increased more than 5x recently. It's a combination of production increases and also oil price increases. We're on track to generate about $200,000 in revenue this month. That's net to us. And our reserves are up via the Carlyle acquisition by over 100,000 barrels and our NGV 10 is up by almost $1 million. As I said upfront, the waterflood project in Fouke has been initiated, we picked up some additional acreage from an offset operator. We're looking -- we're in the process of unitizing all the leaseholders. And then the Carlyle One acquisition allows us to take our equity interest in that water flood from what was originally 32.5%, now upwards of more than 50%, probably closer to 55%. And so will add 50 barrels a day and another almost 1 million barrels of reserves. So we're really excited to move this project forward. And then additionally, we've kicked off an organic recovery project in -- we're in a pilot product tick up in the battery area pine mills. This is where we inject nutrients into the formation. We take some of the existing, let's call them, microbes, get them excited and then we use them to essentially dislodge some residually trapped oil and increased production and, most importantly, decrease water cut. So that has been successfully undertaken, and we'll talk about the results here in some upcoming slides. I think overall, what we're trying to do now is to close the gap. We have a -- an NPV-10 of about $10 million and a market cap that is about 2.5. And we believe that, that is too a gap. We're almost going to make 10% of our market cap in free cash flow this month. So we think there's a lot of room to move in that share price and our objective here is to get it headed in the right direction. And again, ultimately, we want to grow this company to be a midsized E&P. And so that's where we're headed. If we go to the next slide. So again, let's talk just a little bit briefly about the asset where it's located. So the pine mills field is shown on the right there. So it's an elongated field. It's about 4 miles long and a half mile wide, got 17 producers and 4 injectors. Essentially, has a so injection with the exception of the S&M battery there, and that's editor The reason I point out is that we're in the middle of oil food country. So whatever we need to do, we can do relatively quickly. And also, given the competition of service comes out here, the prices are very good for our services. So it's a very good place to operate. So if you go to the next slide, we look at the quality of this field. On the left-hand side of the slide, what we're showing you is the original development in the discovery of this field. The brown lines represent faults that trap the oil and the black dots represent wells that have been drilled. And then those -- the black lines are comp-structural contract line. So one of the horizons, which is the here. So the field is -- mature field, it was discovered in 1949. As I said, it's about 4 miles long and 0.5 mile wide. The important thing about this field is that it has 4 producing horizons, so not just one, and they're also quite shallow. So anything we want to do here is relatively quick and cheap because the formations are shallow and they're also incredible quality. So where it says the average permeability is 1,100 millidarcies. What that means in kind of layman's terms is that if you saw this rock on the surface, they would look something close to beach sand. So as a result of that, when we drill a well into this and we complete it, we don't have to frac it. We don't have to stimulate it. We don't put an asset down. It flows immediately, and it flows quite well. So that is an advantage in this part of Texas, and that the rock quality is so good. So if you look at what was here originally, the 38 million barrels originally in place. We produced just around 12.6 million, which is about 1/3 of the recovery, given the quality of the rock, we think the recovery efficiency can be 50%. So we have another 6.5 million barrels to produce. So a lot to play for here. That figure on the left is what it looks like from -- when we have a 2D seismic survey shot over it. The next slide, which I'll show you in a second here, it shows you what the southern portion of the structure looks like after we shot 3D and it's a much different picture. So if we go to the next slide. So on the right-hand side of this slide, what we're showing you is a picture of the field after it's been under 3D. And again, we're in the very southwestern corner of the field. On the right-hand corner, you see that large black line, that represents that main bounding fault. And then -- if you go to the left, you'll see another black one and then you have the wells, the A1, AL1, all along that fall. That's a fault that didn't -- we couldn't see it on the 2D, but you could only see it on the 3D. And as a result of that, the field was discovered in 1949. In 2021, the Fouke 1 well was drilled, and it found the reservoir in initial conditions. So it came in a we said 140 tray as did the Fouke 2. So it is a field that is -- has a lot of complexity to it. It's not as simple as was originally mapped and it has a lot more surprise as we think in store. So in this area is where we're initiating a waterflood. So we, as Buccaneer participated in the Fouke 1 and Fouke 2, those wells were drilled by our partner, Cypress. So we had essentially 1/3 of those wells, Cypress has 2/3. We then went out and recently purchased the Carlyle One well. We bought that -- and after we drill the Allar 1 well, we picked up the acreage that include the Daniel well and the Turner well. Now that acreage that includes the Daniel Turner well, that's an area that we will place water injection, particularly turn location and then we'll drive oil towards the fall, towards the Fouke 1, Fouke 2 and the Carlyle well. So now we have all the elements in place to essentially get this waterflood moving. And as I said, we are in the process of unitizing all leaseholds out here. If we just step back and talk about the Carlyle One acquisition. We purchased this recently. We paid $425,000 for it. The effect of the date is 1/1/2026. At the moment, it's making 25 barrels a day and at current prices, $90 a barrel net to us, it's making about $63,000 a month of free cash flow. Similar to the Fouke area, the operating costs here are very low. At the moment, they're about [ $67 ] a barrel about, so it's exactly what they are. Once we have assimilated into our operating we will drop this to probably below $5 a barrel, which is what the Fouke 1 and Fouke 2 were doing. Again, the reason we picked it up because of its water fill potential, the remaining barrels on primary for the start of the war for about 28,000 barrels. Once we start the waterflood, we'll get an uplift on that. And we think we'll produce another 200,000 barrels from this particular well. At the purchase price of $425,000, we paid about $2 a barrel. If we look at the economics of the purchase at prior prices, and I have a slide about this coming up here in a second. At prior prices, before the last run out, we were going to have an NPV TAM of about [ $760 -- $3,000 ] and an IRR of 43%. Now with the run-up in prices, that's increased to close to $1 million of NPV-10 on and an IRR of 85%. So it was a very good acquisition, both from a pure economic standpoint and then also from a strategic standpoint, allowing us to increase our equity interest in the South waterflood area and also the fact that we will probably wind up at 55% equity interest, take over operatorship. So it will be an important well -- is an important well for us. The Turner 1 well, we recently returned to production, and it's making 5 barrels a day. It will probably increase to close to 10. It's pretty well depleted. And as I said, it will be used for an injector. But while we're negotiating with the land owners to form this unit, we thought it should generate some revenue. And so as a result of that, we are producing that well today. So we are seeing a little bit of increased revenue as a result of the Turner production. So if we go to the next slide, we'll talk about just the Carlyle One acquisition and it's economic. So -- what timing on the slide is essentially two forward curves. Pre-close, when we negotiated the deal, which is the green line there. And then post close after we completed it. And you can see that, again, because of the conflict in the Mid East, it was started by Mr. Trump, the price has increased dramatically. The returns have increased incredibly. But regardless of our -- let's call it luck in this case, it was always going to be a great acquisition for us because it has very little OpEx has, great production rates and the original payout was less than a year. Now that the prices have increased, our returns have increased commensurate with that. And now we see our payout down to less than 6 months. So it was a really key acquisition for us. And again, the nice thing is that it will allow us to become operator of the waterflood, which is important. So we'll control the whole area once again, and we don't have Cypress as being the operator. All right. Thanks. If we can move on to the next slide, we'll start talking a little bit about our organic or recovery project here. So organic recovery, just a quick definition here. This is something where you essentially take nutrients. You feed microbes that are already existing in your reservoir. These microbes then bloom and they multiply greatly. And then after they multiply and spread throughout the reservoir, they then And in the starting phase, they turn from hydrophilic to hydrophilipic. What that means is they start to look for new sources of food, and that is typically in the areas around the rock face. And so what happens is that microbes then this launch portions of oil that have been trapped in IO areas that haven't been swept by the waterflood or attached very difficultly to the sand face itself. And so it releases this oil so it can now be produced. Why it's attractive is that it's best for mature waterfloods that have the right microbes. So you've already swept this area, you have injection in place and so you can easily implement it. it's also low cost. You don't have to do all at once you can do it in stages like we've done, you do testing and do pilots. And -- so in this case, the Service County, which is ex service going hunting, is willing to participate in the risk. So they will give you a discount And then if you are successful, then we'll make some money on the backside, which is fantastic. So you only pay the full cost once you've already produced the barrels. So we didn't find the now because we've been looking at it for quite some time. It took a while to grow these microbes in the lab. We did the injection in mid-January, and we're looking to expand it now in kind of late April. The is essentially complete now. We've gotten, we think, most of the information we need from it. What I'm showing on the right-hand side of this slide is a couple of examples for other parts of the world where they implemented this, the lines there represent either total production or water cut. And then the red vertical bars represent the treatments and when they did them. In some cases, they had 4 treatments like a field A and then in the second case, they did 2 treatments. And in both cases, you've seen production increase and water cuts decrease. They're seeing about -- and these examples about a 25% to 30% increase in productivity. We've actually seen a lot more than that. We saw originally about 100% increase in production. That has tailed off a bit, I'll show you on the next slide. But we've seen a significant decrease in water cut, which is important because water production and handling and production of water requires power, and power is our biggest operating cost in those areas. So if we can reduce that, it really straight down to the bottom line for us. So if you go to the next slide, we'll look at the results. We look at the area first and then to look at the results. So on the right-hand side of this, there's a map. This is just the northern part of the field. It has a single injector and it has 4 producers. We treated 2 of the 4 producers, the 206 well, which is the well to the furthest north in the field and then the 202 well, which is the well that's closest the injector and up right against the fall. The injector that we treated is the 303, which is shown there in the red dot. We did it in January. We treated it then we had to shut the wells in after they were treated -- and shut the ejector and after it was treated. And then we ended up shutting the entire field in for 4 or 5 days here because of some weather-related issues in Texas where they're not normally expecting snow here, but we've got some snow and so we shut the field in for almost a week. And then we return the wells to production, and that's when we start to see the increase. So as I said initially, we saw 100% uplift in production plus we saw a very significant reduction in water cut. So in the case of the 206 well, the first well to the north, that well is making about an 80% water cut. So 2 barrels of oil for every 10 barrels of fluid that are produced. In the case of the 202, it was about a 90% water cut. And in the case of the 206, it went to a 0% water cut. So we only produce oil. In the case of the 202, we went down to about a 40% water cut. So very significant changes. Again, along with an increase in production. The 204 and the 307, we didn't see any particular increase in either of those. So as we're running the pilot, again, the pilot area gets injection water from not only Battery 3, but also what we call Smith and Messles battery to the Southeast and 2 wells in that area went down. So Messles -- the Wagner 1A. Those wells went down. Those were big high-rate producers of water -- oil. And so when they went down in a very low price environment, we are hesitant to put them back on because they did not make much revenue for us. So we left them off up until this week when we returned the Wagner to production. When the wells came off production, we saw a decrease in the pilot area, oil production but the water cut stays significantly reduced. So we are bringing these wells back on now, bringing -- the Warren will be proud on this week. And we expect to get 12 barrels a day just from that well. And then we expect to see the oil in the pilot area increase another 10 barrels a day, and we'll share that on the next slide. So if you go to the next slide. So here is the history of this, which I just talked you through in a word. So on the vertical access there as shown oil production barrels a day and then the y-axis is going to be -- or sorry, the x-axis is going to be time. So -- the green dots represent daily production numbers. So you can see prior to injection, we were making 15, 16 barrels a day. After we pumped the injection, the field was shut in due to weather and then we restarted the field, restarted this area in Battery 3, you can see we went from rich 15 barrels a day to up over 30. And then we had trial problems with the Wagner well in met as well. And so we had a significant reduction in our injected water. So as you can figure out from that -- from the production subsequent to the Virtus injection reduction there, we thought the decline in the injection for a period of time. And then ultimately, we recognize that, particularly -- 1A need the facilities work. So that work has now been completed. And what we expect is that we'll be back up to 25 barrels a day this week once we get the 800 barrels a day in the -- back into the 303 injector. So we are basing that on almost all these upticks you see in production or when we can get the Wagner back up and running again. And when we did that, we saw an immediate production response. The issue in the Wagner is that the well is fine. We just had a problem with the facility and we couldn't separate the oil from the Walmart corrosion issue. So that has now been replaced, and we will have that back up either today or tomorrow. So we're working on it for a little bit. I mean, as a result of that, we expect to see -- the pilot production increased back up to 25 barrels a day. However, we don't expect to see any significant increase in water cut. The 206 is still basically 100% oil. As part of this project, we had to get water samples from all the wells in the area, and we struggled mightily to get any water out of the 206 well. So what the field had to do was produce the well as much as they could and then they would take an oil sample basically heated up, get us much water that got out of it and then that was what we had sent to the lab. So again, water cut there is still essentially zero. That decrease in injection caused the 206 and the 204 to essentially shut in early. So these wells were pumped off. They just didn't have enough fluid to produce continuously. So before the injection was decreased, the 204 and the 206 were producing 24/7. And then after the injection was decreased, they were cycling on and off. And that's done automatically after wells themselves. So when we get back on, we expect to see the production up again. However, given the fact that we have significantly reduced the water cut and significantly reduce the amount of water we're moving, we are very excited that this has worked in a pilot project to the north and we look to expand it field-wide after we do a second treatment here of the injector in late April. We're going to pump that towards the end of this month. We don't have to shut the field down again. And what we expect to see is another uplift in production and a further decrease in water cut. So we are looking forward to pumping that now given the current pricing. Right. So if we go to the next slide, we'll see how this all sums up from a cash flow and production perspective. So the figure on the right shows our forecast production for the next 2 years, really focused on the first year here. And the upper corner of that plot, we're showing our field netbacks. So the amount of profit we make per barrel and the various assets. So at a $90 oil price and we're actually getting more than that today in the field. We see a netback in Pine mills, again, where we produce a lot of water, about 62 barrels. In the Fouke area, which would be Fouke and Carlyle, we make about $85 a barrel on profit. In West Texas, which we talked about today, our netback is $75. So these are very high-margin barrels that we can produce here. The forecast on the right is based on the assumptions shown to the left here. And -- so that assumes we continue along with the organic ore recovery, the Carlyle well produces as expected and just declines, and then we implement the Fouke Waterflood in October of this year. And so that gets us just about 200 barrels a day at year-end. At current pricing, if you look to the bottom of that slide, you can see that we're currently making over $200,000 a month in free cash. Again, at the moment, that's almost 10% of our market cap. Once the OOR project is fully implemented, that will increase to $300,000. And then when we add our portion of the waterflood. So we're assuming here that we get 50% of it. We might have another 10% more than to 55%. We'll have cash flows of $357,000 a month. So the cash flow story here is very robust. We are really generating a lot of cash, whether it's at these elevated prices or price that the cash flow here is very good because our operating costs are quite low. If we go to the next slide, kind of sum up. From our perspective, we believe that strategic growth is well underway. We're seeing increasing cash flow and reserves. Our cash flows have increased 5x in recent times, and that's from a combination of production rate increases and along with the oil price increases. We are on track to generate over $200,000 a month in that this month, April '26. And our reserves and our NPV is up as a result of the Carlyle acquisition. The Waterflood has been initiated. The acquisition of Carlyle well allows us to increase our equity percentage there by a significant amount, so we can become operator, and we'll add 50 barrels a day to our production levels gross, 25 net. The Carlyle One acquisition, a strategic important allow us to do that. The organic oil recovery project has been a success. We are looking to expand that field wide. And when we do, we think we can see a total of 45 barrels a day coming from that. And we're focused here again, as I said, on closing this gap. We have a market cap that is we be too low, $2.4 million. Our NPV-10 is 9.6. And again, we need to move that share price up to something that resembles more our value. We're producing a healthy cash flow at the moment. It's almost 10% of our current market cap. And as I said, we expect to be at or above 200 barrels a day by year-end 2026 just through our organic development of our existing assets. And with that, I thank you for your time, and I will open it up for questions. So thank you very much.

We have had a number of questions, pre-submitted and submitted live. [Operator Instructions] Our first question is Carlyle One looks highly attractive on a per barrel basis with strong IRR and fast payout. The question is scale. How repeatable are opportunities like this? And can you realistically build production meaningfully through similar deals?

So they are repeatable. It was clearly easier to do when oil prices were lower because expectations of sellers were almost in line with people that were buying it because we got a very flat forward curve. I think in today's environment, until we see some settled settling down the price. It will be difficult to replicate that exactly. But there are people that are realistically looking to sell things that have reasonable returns. What we're looking to do is buy them strategically. So things that make sense to us like Carlyle. So yes, we believe there are opportunities out there. But we're probably not going to do anything until we see something reflected in our share price because we believe we made a very good acquisition and the didn't move in the right direction. So we don't want to do anything dilutive to the share price. And as a result of that, we're probably going to hold off and just focus on what we're doing internally to grow our barrels before we would do another inorganic opportunity.

And are you looking to acquire any more projects?

Yes. We're always looking to acquire more projects. We need to grow. We need to get bigger. We need scale. So we're always looking. It has to be accretive, it has to be appreciated by the share price in the market before we'll do it. Like I said a second ago, given the nature of the shape of that curve, it's kind of difficult to get buyers and sellers on the same page because they may have a different view of what the future looks like. But once we get some settling down that, we believe it will be back into an area -- into an environment which strategic acquisitions are possible. And what we're looking for is, again, focusing on the areas where we operate, we operate relatively leanly and we do things that allow us to drop our operating costs. So we think we can -- we have to find opportunities to do that. So if it's just a straight acquisition where we're buying barrels, we don't think we can add a new value either through further development of the asset or a lowering the operating cost to improve the revenue, we won't do it. There has to be a strategic element to it for us before we'll do it. And when we see that, we will move. So at the mode we're kind of focused on what we have internally, but we are continually looking for opportunities all the time, definitely.

My next question is, was Carlyle One something you've been tracking for a while? Or did it just come up as a quick opportunity?

No, it's something we've been tracking for a while for a couple of reasons. One, it was a very good producer in the same area, and we knew it existed. Two, we needed that well to participate, as you can see where it was located, structurally on the same side of the fall as the Fouke 1, Fouke 2. We needed it to participate in the unitization process before we could implement the waterflood. So we had our eye on it for quite some time. Our partner in the project, Cypress wanted to wait till depleted before they would move on it. And we viewed the well differently. We felt to have a longer life than the Turner location, which we picked up to the West. So we moved quickly, and that's why we bought it 100%. So yes, we've had our eye on it for a while.

What are the company's short- to medium-term growth strategies?

So it's a combination of all the organic things I just discussed and then looking for the inorganic opportunities where we can add value and increase the value to the company. So -- those are the two things we're doing. Again, we can't be specific on certain opportunities other than the things we laid out organically in gestation we just made, but that's what we're looking at.

Our next question is, you've highlighted a gap between reserve value and market capitalization. What specific milestones, whether production levels, cash flow consistency or project delivery do you think will actually change market perception and start to close that gap?

Again, that's a good question. It's a challenging one. From our perspective, what we're focused on is creating value. So adding reserves profitably and generating cash. And so from our perspective, we believe generating cash, showing the market that we are a very profitable business is really key to moving that -- to closing that gap. So that's what we're focused on. But so increasing production, increasing value and increasing cash flow. That's what we're focused on doing to try to close that gap.

Our next question is your presentation shows net cash flow of over USD 200,000 per month at current prices. Can you break down how much of that is coming from stable base production versus recent improvements? And how sustainable that level is if oil prices or production fluctuates?

I can't break it down on the fly. I mean, again, I think the best way to do it is if you look at that figure that shows you the production profiles, it gives you the individual cash flow components. So how much we make on each barrel we produce in each one of those wedges and you can -- whoever asked the question, can calculate themselves. We -- and then prior presentations, we've done it at $60 a barrel. So you can see the difference between the two. So again, if you just take the netbacks, multiply it by the production rates there you can get those numbers. But I don't want to do it on the fly because I'm certain I wouldn't be exactly accurate. So anyway, it's there for someone that would like to delve into it a little deeper.

Our next question is you highlight the Fouke waterflood as a key driver, targeting startup later this year. What are the main risks to timing and execution? And how material do you realistically expect the production uplift to be in the first 12 to 18 months?

So the timing -- so what we need to -- so there's two issues got agreement with our partner, the split in equity between essentially them and us at this point. There's only two of us in that discussion. And then secondly, we have to get the buying of all the royalty owners in the three individual leases we have there. So those are the -- getting those agreements done is the key. We then have to get it approved by the Railroad Commission submitted approved. If all the landowners and all royalty owners agree, that doesn't take much time. So we are expecting that to take us through the end of the summer to get done. At the moment, Cypress, our partner is driving it. Now that we've picked up the Carlyle well, and again, they found out about that a couple of weeks ago, like the market did, we're in discussions about how to accelerate that. I mean what our how involved we're going to be in that process now. So that's an ongoing discussion. That has its fits and starts because they were a little surprised we did that. However, it's moving forward. So we're expecting, again, by the end of the summer to get all those agreements done. We expect it to be very material. I think we've -- as I put in here, we expect at least 50 barrels a day of uplift and up to 1 million barrels in total recoverable over the life of the flood. Now the life of the flood is going to be something similar to like 10 to 15 years depending on the oil price. But -- so there's a lot of opportunity in that very small area. And so again, I think it's very realistic, and it's the reason that we picked up the Carlyle is because on primary, even though the quality of this reservoir is quite good, you still only get about 15% to 20% of your reserves, which leaves a huge amount in the ground and by implementing a waterflood allows us to get 50%. So that's why it's important to end up with waterflood. And again, we have an analog us exactly how it's going to perform in the pine mills area. So we're pretty certain as to what to expect out of this flood once it's implemented.

Next, we have, Paul, how much daily production would you envisage in about a year's time?

About a year's time -- in about a year's time, with no change in what we've just discussed today, we'd be around about just kind of look at the figure, 180, 190 barrels a day at this point. We have peaked at about 2,000 on decline from the waterflood. If the waterflood performs, we've discounted the waterflood a little bit. So if the water plant performed similarly to what we've seen in the mills area, it will probably be probably get -- rather get the 50 barrels a day might give an 80-barrel a day of lift. So we could still be about 200 barrels a day. But we clearly need to keep developing, keep looking for other opportunities. What we haven't done is we haven't gone deeper into the -- which is runs more to the much lower in the sequence and the -- producing from at the moment. So we do have other things to do after that. But at the moment, again, our forecast is what we've seen there. It will depend on inorganic opportunities that we see in the market and also oil prices as to what we do. If oil prices stay high, then I think you would expect to see our production continue to increase. If oil prices plummet down to where they were before $50, $55 a barrel, then we won't be as aggressive on developing the other opportunities because they take a higher oil price than that to move forward.

And how have high oil prices change your approach?

Well, I think the high oil prices have kind of slowed down our look for opportunities like Carlyle. When -- if you look back at that slide on the oil price forecast, when you had a very flat oil price, it was easy to get people on the same page about the value and then if we could find a way to increase that value through a change in operating procedure or whatever it may be adding on a pole or water funding or something, we could easily -- more easily concluded an agreement with a seller. Now that the oil price is so high, I think it's really slowed down the inorganic opportunity. We're looking more for the stuff within our field. So how oil prices -- if you look at that -- the shape of that curve, it's a very steep run-up and a very steep drop off. So it's not -- based on what the forward curve is telling us today, it doesn't look like a sustained high level of oil prices. So we don't want to get too hard -- too far ahead of ourselves here. But we've also started to look for behind pipe things a little more aggressively, marginal wells, like I mentioned one well in the case of the -- it was a huge producer of water and it made very few barrels of oil. So under the previous price scenario, we wouldn't return that well production because it made like a barrel or 2. When the oil price is $90, then you think more about those very marginal wells returning to production. So that's kind of the way it's changed our thought process.

Our next question is as you're targeting 200 BPD for end of 2026, how will you then push forward to an ambitious target of 5,000 BPD in 3 to 5 years?

It will be organic. It will be an organic opportunity, either something more development-oriented or an acquisition of a larger or a number of additional producing assets. That's what it's going to take. So we can't do it all, and we can't do it all organically. We need to go out and look for inorganic opportunities.

And what is the outlook for revenue and profitability in the next financial period?

I mean you can see it there, so we're making less -- if nothing changes, we don't do anything else, we're making $200,000 a month. So we may be selling more than that. So let's call it $2.4 million per annum. If we implement all of our projects, it goes -- it increases. We don't have any significant capital plans. We're not drilling any wells. We don't -- we're working on our facilities. So we don't have a huge amount of CapEx outlay. So if we just take the revenue generated per month, that would be our expected cash flows for the next year. So there's outside of an acquisition opportunity. We don't really see much change in either our operating expenses or our revenue. What we have to do is deliver on the projects and move straightforward. Now the question is what happens in the with the OR? Do we continue to see an increase? Or do we just drop our OpEx as our market decreases? Again, we got some of the answers from the pilot. As that expands across the field, we'll get more. So we know it's a beneficial thing to do. It's just how it manifests itself in profitability. We're still trying to figure out. So there is some uncertainty there because it's a new technology, and it's definitely new to us. But at the moment, it's a very profitable opportunity. And so we're going to continue it. So there is some uncertainty bar there. But again, given the current oil prices or even oil prices that are in the, say, mid $60s to $70s, which is, I think, what people are expecting, we're a very profitable business at that point because our OpEx is very, very low.

Our next question is, given the disconnect between the NPV of book and the share price, have you considered some share buybacks to hold the shares in treasury for when the share price catches up with the true value of the company?

It's something that we talk about at the board level, but we haven't implemented that clearly. It's definitely something to consider. I think from our perspective, given the kind of projects we see in the field, we see IRRs north of 40% as high as 100% depending on what we're doing. We think we're better at the moment, we're better placed putting the money in the ground and generating where we do from it than buying our shares back. But that will change as the share price moves or doesn't move. So that's something that we've definitely discussed and we'll see how it plays out. So it's not something we are going to do in the near term, but it's certainly something that we would discuss at the board level.

Next, we have what's happening with the Bitcoin opportunity?

Zero, nothing. The Bitcoin opportunity was driven by an excess amount of gas that we were seeing in the Fouke 1 and Fouke 2 wells. We drilled LR1 to get what we considered the sufficient amount of gas to implement that. The LR1 well didn't work as we mentioned in front because we're too close to the fall. So we don't have sufficient gas volumes now. Once the waterflood starts and we increase the reservoir pressure in the area by injecting water, the gas volumes will decrease. So there will be no -- there won't be sufficient volume of gas -- There is a sufficient volume gas now. And as we move forward and we put water in the ground and raise the reservoir pressure, the gas volumes will decrease. So in this part of the world, where we had originally planned to do it, we won't have a gas volume -- sufficient gas volumes available to do that. So it's not happening. Now -- we have seen other opportunities in Texas onshore for gas because gas is still very, very inexpensive here to implement something along those lines. But that's not something that we are actively pursuing at this point in time. It was a great idea when we had a commodity essentially that we were flaring we have -- we're just using it as to cover the tops of tanks. It was almost a nuisance, but going out and looking for other opportunities without having kind of practiced it in our -- on our own backyard. It's not something that we're actively pursuing at this point.

Our next question is our Premier Miton and still committed to their investment and pulling their portion at weight, i.e., participating and placing to avoid their own dilution in the various fundraisers.

Those are really questions for the two funds to answer. I'm in regular contact with Premier Miton, and I know that they are very supportive of us and story. I'm not that actively involved with appeal hunts. So again, I think that's -- those are really questions better answered by them. From everything we've seen and every time that we've spoken to Premier Miten in particular, they've been very supportive. For instance, I think I mentioned on our previous call. Premier Miton was one of the people who mentioned to me, firstly, about organic because they were big investors in hunting and they believe in the technology. I was new to it and I wasn't aware of it, and then I started to dig into it and I recognize it would be something that was a real opportunity for us. So there's a good exchange of information between ourselves and Premier Miton. So I would say probably yes with them. In the case of I couldn't answer the question. But again, I think those two investor groups are best placed to answer that.

Our next question is, will the waterflood work bring us up to 200 barrels a day? When will this work take place? And can it be paid for organically?

So yes, they can pay for organically, and we're doing the work now. So the work isn't a great amount of work just to put it in perspective. What we have to do is convert the Turner well to an injector, which is relatively cheap to do because we have the wells already drilled. We have tubing in the hole. So all we have to do is do a workover pull out the rods, put in a packer, a permit from the state and then start injecting. The bigger expense is going to be running a line from about -- it's a little under a mile 4-inch line, about 3/4 of a mile, from one well to the Turner location. So that is something -- it's relatively inexpensive to do it's just 4-inch pipe and we already have the right way. So -- it's something that we can do internally. The bigger job is not the, let's call it, the CapEx or the implementation of the work over the well and laying of the pipe. Their job is getting all the partners, the royalty owners to agree on the split of the revenue stream in the units because when you start injecting water into the Turner location, the royalty owners there are no longer going to be receiving oil that's produced on their lease. The oil will be produced from essentially the South or the Carlyle 1 well. And so you have to get an agreement amongst all parties to share the revenue in some formula between all parties, and that's the challenge. So that is the bigger job to do. Putting -- implementing the work itself is relatively easy because we have all the facilities available in the Pine Mills field, and we have an excess of water available to essentially put into the ground in the Fouke area. So it's not a difficult project to do, and it's not expensive.

Next, we have -- you mentioned a $200,000 in impairment. How do you intend on using this cash flow over the next 12 months to organically grow the company?

Well, we're going to use that money to implement the organic ore recovery and the waterflood. That's what -- that's the first priority, cover our expenses associated with all the legal fees around the implementation of the orphan unit. That's foremost we'll do. If there is sufficient money left over, then we'll look to start paying down some of the long-term debt that we have. So those are the priorities at the moment.

Our next question is when the price of oil goes back down, will you reduce the output due to some wells not being economical? What would production levels be at GBP 55 a barrel?

So at the moment, everything is producing. And so the question is, it's an old field. So wells in any one day or will go down because of the problem pump unit or a pump or something and relatively inexpensive to return. The best example is the case of the Measles 3, where we're making 400 barrels a day of fluid and 1 to 2 barrels a day of oil. A well like that, if it came off production in a low price environment, we wouldn't return it to production. So we don't have many wells that have that low production, but those low rate wells, we wouldn't return production -- we wouldn't return to production in a $55 environment. How many of those? Probably all of them. How much that would add up to a per barrel basis -- per barrel per day basis? It's difficult to estimate at this time because wells decline over time. But I would say it would be probably on the order of 10 to 15 barrels a day, maybe up to 20. But again, that's where the cost to return the well to production doesn't pay back because the oil price is so low. And the amount of fluid that we're moving to get those incremental barrels of oil is too high. As I said, during this -- during my presentation, hopefully, our biggest cost out here is power. And power, the amount of power we use is directly related to the amount of number of barrels that we produce -- barrels of fluid that we produce. So that always comes into me. So when the cost to move those barrels of fluid, doesn't pay out given the number of barrels of oil that we produce, that's when we won't return something to production. So it's a constant discussion. It's something we look at every -- literally every day. So it's difficult to predict now. But like I said, those are the ranges.

Our next question is, is Bokoni now becoming an acquisition target in itself given GBP 1.5 market valuation versus cash flows and barrels on the ground?

SP-37 I think everybody is -- I mean, -- we could be. That's not something that no one has reached out to us or anything like that. But everybody, I think, would be at this point, if you're generating good cash. Again, that's definitely not something that we're actively trying to pursue in any way.

We are now moving on to -- final question for today. If you have any further questions, please e-mail the team who will respond to any questions that we covered this afternoon. The question is, please outline the news flow across the next few months, which will bring production levels up and by how much for each?

I think the best way to do that is to look at the slide I showed you where the where we've seen the increase in production. So again, it's primarily 2 areas. It's going to be the implementation of the organic ore recovery projects and those incremental steps that I've shown there, and then it's going to be the start-up of the South waterflood. So from a timing perspective, the next -- so we are expecting to pump the next job late April -- in the organic and we have another one in August. And in the case of the waterflood that is due to start of production in October. So those are the things we know about now towards the end of the year and those half correspondingly as shown in that figure increases in production around those times.

Thank you. That's all the questions that we have time for today. So I'll hand back over to Paul for any closing remarks.

So thanks very much, Ivy. So again, thanks, everyone, for joining us on this call. Like I said up front, we're excited about the opportunities within the company. We've got every well producing that we can at the moment. We've had success with the organic oil recovery project. We're excited about the Carlyle opportunity and how that impacts the South waterflood. And the current increase in price has made the cash flow generation significantly improved from where it was. And so again, those dollars that we generate internally are going to be put back into projects that we think will have a fantastic return. So we're really looking forward to the remainder of 2026 and how we implement our projects and grow our production. Like I said, we're always keen as you look for a new opportunity where we have an advantage to add to our production. And we'll keep everyone informed. We're focused on driving up this or driving down that gap between our cash flow, our value and our current share price, and that's now is an important part of our focus because people that invest in us need to see a return, and we're very thankful for those that have put their faith in their money to our shares. So thank you for the time. and I look forward to the next opportunity to give you an update on what we're doing. Have a great day.

Thank you to Paul Welch for joining us today. That concludes the Buccaneer Energy Investor Presentation. Please take a moment to complete a short survey following this event. A recording of this presentation will be made available on Engage Investor. I hope you enjoy today's webinar.