Pleased to welcome back Kolibri Global Energy, the ticker on the NASDAQ's KGEI, joined by CEO Wolf Regener, CFO Gary Johnson. With that, gentlemen, let me turn it over to you. Thank you, Steve, and thanks everyone for joining us here today. Forward-looking information, our disclaimers, non-GAAP disclaimers, all these can be found on our website in our corporate presentation that's there, and this version is on the website. Kolibri, for those of you that don't know much about us, we are an oil and gas producer that operates the Tishomingo Shale field in Oklahoma. We try to run our business in a financially stable fashion, keeping our debt low, debt to EBITDA less than one. We've had really good cash flow growth over the last few years of high net back production, how much we make per barrel of oil that we pull out of the ground. We've been fully funded in 2026 for our drilling program as we have been in past years, and we look forward to continuing to do that in the future. We use both our cash flow and our existing line of credit with Bank of Oklahoma. We have a $75 million line of credit. When we drill wells, when we drill in batches, that's a lot of cash going out, so we draw down on the line of credit, then we pay that back from the cash flow from the existing wells, as well as the new wells that are coming on. We've got what we consider a good high-quality asset. About 40 MMb of proved reserves, 57 MMb of proved probable reserves. The proved reserves are split into this is as of the end of last year, by the way, because this is the third party reservoir engineering report from Netherland, Sewell 29% of that was in the proved developed producing category, and 71% is in proved undeveloped. You can see that Netherland, Sewell believes we have a lot of room to drill more wells here. As Steve said, we trade on NASDAQ under KGEI, and we also trade on the TSX as KEI. Share price has been fluctuating a bit, obviously, as everyone probably sees, but at the $6.50-ish mark. Our U.S. market cap is about $234 million. At the end of last quarter, we had about $42 million in debt, gives us an enterprise value of $276 million. That compares to last year's reserve report. At the end of last year, the Netherland, Sewell reserve report of that 40 MMb of proved reserves gave us a valuation of $441 million. I want to point out to everyone that down here at the bottom of this presentation, you can see what the oil price assumptions were that they were using. They were using $58 in 2026. We're obviously quite a bit higher than that right now. $63 in 2027, $68 in 2028, et cetera. That is at those low prices, gave us that $440 million. So at current prices, that valuation would be much, much higher. Proved and probable reserves, even with those low prices, was just under $600 million. Again, compared to our market cap of $234 million. We are in Oklahoma, so the Tishomingo Shale field, and we're about halfway between Oklahoma City and Dallas, just for an overall orientation point of view. Originally, we drilled for the Woodford Shale out here. The Woodford Shale was mainly gas. You can see it was only about 15% oil. The balance was gas and NGLs. We had drilled and/or participated in about 40 wells. We had about 12,500 acres at the time, which you see all the pink and purple on this map here, that's Exxon. So Exxon was buying out everyone around us. We were the last holdout. They finally brought that offer up to $147 million. We said okay, but we wanted to hold on to the rights to the Caney and the Upper Sycamore. These zones are down between 8,500 ft and about 11,000 ft, roughly, and we drill horizontally after that in those intervals. But the Woodford is about 300 ft, 350 ft below the Upper Sycamore that we have. We've grown that acreage position to about 17,000 acres now, and that's where all our reserves are coming from. You can see from this, last quarter, we were about 71% oil. The balance was gas and NGLs, and that's where all our reserves are from. We're very grateful that we held on to that position there, those horizons. At the time, we'd only drilled one horizontal well. It was by no means economic, but we felt like we could make economic wells out here, and Exxon didn't want to pay us for what we felt it was worth, which again, I'm glad that that's what happened. That's what created our value now. Our guidance for the year, call it a midpoint of about 5,000, increases us hopefully from last year from between 17% and 30%. Revenue, again, up as well, 37%- 48%. Adjusted EBITDA midpoint is about $60 million, which is a 33%- 47% increase over last year. Keep in mind that as of our June forecast that we put out, that was assuming a $70 oil price. Higher oil prices should obviously generate hopefully more adjusted EBITDA and revenue, et cetera, assuming that our production numbers hold up well from the wells that we're drilling and bringing on production. Adjusted EBITDA over the last few years, to give you an idea of what was going on, we're holding in right around the $40 million mark, roughly. These boxes down here, when you see these are the blended oil price. So what we get for our 70% roughly oil, plus the gas and NGLs, so that blended price. Decreased from 2022 of around $80, all the way down in 2025 to just over $49. So in spite of that drop, we've been able to keep our adjusted EBITDA nice and high. This year's, with that $70 oil price assumption, is about $58.50, call it, to generate our forecast of that midpoint, call it $60 million. We also have a share buyback in place. You'll see us hopefully buying additional shares here later on this year. Right now, we'd be basically paying back some of the payables and debt from drilling the wells that we're just bringing on now. In 2026, we entered with a strong 2025 exit rate because we brought some wells on production in the fourth quarter. Looking to continue drilling more wells, the three Clifton Mack wells are Caney wells. We just announced here recently that we completed those successfully, drilled out the plugs, and they are in flowback. We're getting our fracture stimulation fluid back in order to wait for the oil and gas to start producing. Once we have sustainable and solid flowbacks and production rates, then we will announce that as well. We're also testing a new bench. This is not in the reserve report. It's called the False Caney. It's in our Lovina well, and we've successfully drilled that, and we're waiting on the fracture stimulation crews that'll come in early in the fourth quarter. After that well has been completed, fracture stimulated, and flowed back, then we'll announce those production rates as well. As I mentioned, we'll continue buying back some shares. Talking about the benches a little bit, the different horizons that we have out here. All of our proved undeveloped reserves for Netherland, Sewell is now in the Caney only. The Caney only, those 40 MMb of proved reserves come from about 11,500 net acres that we own. We are testing the False Caney. Why are we testing that? When we drilled all these wells through to get to the Caney and originally to get down to the Woodford, which is down below, we have logs that go through the False Caney and the Caney, the T-zone, and the Sycamore as well. But the False Caney, from all the logs, looks like it should be a productive interval. We have petrophysics from even from a whole core, which showed excellent shale reservoir quality in the location that it was. We thought this would be a good test, especially because we think it could be potentially productive over almost 10,000 acres. You can see from this diagram, it's a little bit thinner, and it varies across the field. Some places it's thinner, some places thicker. We hadn't drilled it previously because we didn't have enough wells drilled through it to feel comfortable that we could get into the thicker stop and stay in that thicker interval throughout the entire lateral of it. Plus, with the drilling, being able to drill longer and longer laterals, we can eventually drill longer laterals in the False Caney to make better and better wells, even though it's thinner. With that potential for the 10,000 acres, if we can make a successful well here, that'll hopefully be sometime in November released, then that would be significant for the company in that we can hopefully add a lot of reserves to our field here. We've got the T-zone down here as well, which we've tested in a few wells, but in a couple of wells, it fractured up into the Caney as we were completing those at the same time, and it interfered with that completion. We held off on drilling any more T-zone wells right now, and we'll wait till when we have an area that has been depleted down in the Caney, then we can come back in and drill some T-zone wells. If it interferes up in the Caney, it doesn't make a big difference to us. Sycamore-wise, there's some operators in the area that have made some good wells in the Sycamore to the north of us. We have the potential on our property in order to drill some Sycamore wells, but it was a little higher risk to us than the False Caney, so we thought we'd go after that first. This basically goes into the same thing that I just said, so you can peruse that as you like. In the Tishomingo field, all the infrastructure is in place. The gathering system is always less than 1 mi from all those proved locations. Exxon handles our gas, NGLs, so we go into their gathering system. You'll see a fluctuation sometimes between how much gas and how much NGLs comes out, but that's because they are optimizing for their own flows, where they make more money selling more gas and selling more NGLs. We get the benefit of that as well because ours goes alongside of theirs. Oil is priced at WTI less about $1.85 a barrel, and that's been very consistent over years for us, so not big differential fluctuations for us. Most of our revenue stream is really oil related for us. Mentioned Netherland, Sewell doing our reserve engineering, our reserve reports. At the end of last year, they gave us 48 proved locations in the Caney, 24 probables, and 17 possibles. Those are mainly now 1.5 mi and 2 mi laterals. So a couple of 1 mi still. But that's the big change that we had from drilling in these 1-mi horizontals to drilling 1.5 mi- 2 mi laterals. Mentioned that we got our acreage up to about 17,700 acres. We have 45 Caney wells on production, and then three more in flowback right now, and then the Lovina well for the False Caney coming on a little later this year. So by the end of the year, hopefully, we'll have at least 49 wells on production. Our acreage is held by production, so that means we don't have to drill in a particular area in order to hold those leases, but we have the ability to drill where we want to, when we want to, which is nice. Production. This graph is just showing the production growth we've had on a quarter-by-quarter basis. You can see it's been climbing nicely. Our net operating income, same thing. The red line, again, just like those boxes were on the previous diagram, shows what the blended barrel of oil equivalent price has been for us. You can see our net operating income is coming up nicely. Drilling efficiencies. When we were drilling those 1-mi laterals back in 2016, 2017, it was taking about 30 days to drill. By the end of 2024, they were taking us about 12 days. We have gotten better and better at drilling those wells, which had brought the cost down. In 2023, our forecast was for a 1-mi lateral was about $7.2 million, and the average cost for those wells was about $5.5 million. The Lovina wells, which we were able to drill quite quickly, and the mi and a half laterals, we drilled in 10 and a half days. We have the capability of drilling wells in less than 12 days now for the 1-mi lateral and those mile and a half days. Those mile and a half wells, excuse me. Our typical Caney well for a mile and a half lateral has a budgeted cost of about $7.2 million. Operating expense-wise, we are in the lower end of our peers. These are numbers taken from 2025, their annual reports from other public companies that we consider our peers. You can see the green bar here is us, and we are down at the lower end. Most of those wells around, or the operators around us produce mainly natural gas, where natural gas flows out of the ground naturally rather than needing a lift mechanism to get it out of the ground. That leads us also to our operating netbacks, and those were best in class. We are normally in the upper three here. Last year, we happened to be a little bit better than some of the other operators, mainly because we did not have negative gas prices where we were, and some of the Permian operators have been struggling with that. G&A has been coming down year after year. Yearly net revenue, same thing, has been on a nice growth. The red line, again, is the price per barrel of oil equivalent, just to give a reference point. Management team. Myself, over 36 years of oil and gas experience, doing everything from a lot of operations experience, to land acquisitions, to M&A, to financing, and just generally running oil and gas companies. Gary Johnson has over 34 years of accounting and finance experience, over 22 years in the oil and gas industry, including a stint with Occidental Petroleum, where he was Director of Technical Accounting. Dan Simpson, our Director of Engineering, has over 30 years of experience in oil and gas engineering all around the world. Allan Hemmy, our Senior Geologist, has over 16 years of oil and gas experience as well. Our board of directors. Our Chairman, David Neuhauser, runs Livermore Partners out of Chicago. They are a large owner, own about 16% of the company. Lee Canaan is Chair of our audit committee. Lots of corporate board experience and finance experience, including being on Director of EQT Corporation. Glen Brown, lots of oil and gas experience, MidCon and elsewhere, working for Continental Resources, where he was the Senior Vice President of Exploration for Continental. Murray Grigg has lots of science experience, in shale gas, so he is a premier knowledge and, very useful on the technical side of things, on the shale especially. That brings us to the summary. Why us? Reminder of KGEI on the NASDAQ. We've got what we believe are excellent reserves, great property with more upside potential over this. So fingers crossed that this Lovina well does well, and then we can hopefully add a lot more reserves. The Clifton Mack wells, by the way, that are coming on production right now, those were in the probable category in the reserve report last year. They're on the very southwest corner of their property. We operate well. We keep our debt down low, debt to EBITDA less than one. According to another one, so we have a lot of drilling inventory left. Cash flow has been going up nicely. Oil prices being up helps even more. We're looking to return some capital to shareholders later on this year as well with buying back some additional shares. With that, I will open it up to, or turn it back over to Steve and see if there's any questions or anything else. Thanks so much, Wolf. We're starting to see a queue build up here. We got about 10 minutes remaining after I think was a pretty complete presentation. If you do have questions, press that Q&A button at the bottom of your screen, type them in and we'll get to as many time permitting. I do want to start asking Wolf, about what seemed to be a strategic change, and you touched on it a little bit in one of your slides in terms of finally deciding to test some of the other benches. Was there any inflection point that got you to the, "Let's do this now," or was it a series of reasons? It's a number of different things. It's funny because when we first drilled this, I remember looking at the logs with our engineering and geology team going, "That looks really looks good. Why can't we do that?" It was a little thinner than the Caney, for starters, so we went after what was thicker and was more consistent across the whole field. So the thickness on the Caney itself is more consistent across the whole field. Plus, from a drilling point of view, we have to make a very sharp turn at the top of it to get into the top of the False Caney, because it's a little challenging interval that is right above us called the Springer, which every once in a while, bites people in the area and gets drilling stuck and things like that. The drilling of it is a little bit more challenging. Likewise, if we can make some good wells in the False Caney, we'll probably end up drilling more like 2-mi laterals, which with the technology increases that we've had, where we can drill longer laterals rather than just the 1 mi, all leads to better chances to making economic wells in the False Caney. Got it. The plan moving forward, depending one way or the other on the results in the False Caney, would be drill some wells in the Lower Caney, then mix in some of the others in these other benches, so looking forward? Yeah, that'd be definitely my inclination right now. Obviously, then we'll see what these look like, and then we'll plan that out with our team and then propose that to our board for approval on that as well. We actually have a more general question in terms of how economics have changed around being able to drill 1 mi, and even you have progressed from 1 mi to 1.5 mi and now testing out potentially longer, and that's industry-wide. How that changes and how that changes the economics of even the T-zone field, potentially. Yeah, it helps for sure because generally it is not a one for one on a horizontal basis per foot increase on cost. You are able to drill, our best example was where we were able to drill wells in 10 and a half days that are a mile and a half laterals. Call it, this is the same amount for a 1-mi lateral. From a drilling standpoint, we can sometimes drill wells very quickly. That is cost-effective. On the completion side of things, when you do not have to pay for everything to get down to that level and you are just paying for incremental length it is a lower number than a one for one, and so that definitely works. They are trying to figure out what the extent is of having a one for one increase on production, depending on how long you get. So 2 mi seems to be no degradation on that. I know some of the longer things like that Exxon has been doing with different proppants for the tail end of the things in order to try to still get closer to that level. But the further and further out you go, you sometimes lose a little bit more. Right. I have been getting this question a lot recently. I will let you answer it for me. Why does not Kolibri only drill 2-mi wells now, 2-mi laterals? Well, there is a number of reasons. One, we have a pretty steep dip out here, and sometimes you have other challenges where you have a fault that crosses you or something like that, and it is a large enough fault where it does not make sense to cross a boundary and get into something. Sometimes it is also some of our early wells are 1-mi laterals, right? Yeah. You sometimes don't have a choice because you've already drilled part of that. You can drill, let's say, a mile and a half, but you have a mile on the end of it. It just depends on the geology, on the structure, and what's there existing. Then, we have the rights to most everything, so we're lucky in that. Yeah. But on the edges, you still get into something where you can't go as long as you'd like sometimes. Right. A number of questions around capital allocation. This one is, can you rank order your capital allocation priorities? Sure. I'd say, and this is just me, but I think the board feels the same way, that it would be, A, keeping production steady at the very least, right? So whether prices are higher or lower, we want to drill enough wells so that we can keep production at least flat. I'd like to see production at least grow a little bit, and then we can adjust for where prices are or we think prices are in the forward curve in order to determine how much more we'd spend in the field itself. We'd like to allocate some amount of money for testing these new horizons, right, to add value, but really do a lot of the bread and butter side of things to make good wells and keep production going. Then we do want to return capital to shareholders. The easiest way for us to do that up till now has been to buy back some shares in the market. I've been asked a number of questions about dividends and things like that. We haven't made a decision to start a dividend, but one of the things we always are conscious of is when you start a dividend, you don't want to end a dividend. So you want to make sure I feel like we finally got up to that 5,000 bbl a day level where you have enough cushion where you can potentially. That way, you can ride out times where oil suddenly is lower than you anticipated, but hopefully you can keep your dividend going. But, we have not made any decisions on dividends or anything else. But like I said, right now it's keeping the growth going a bit, and then, we'll make a decision on the board level as far as how aggressive we are on the drilling side of things versus returning capital to shareholders. Since I've covered you, your balance sheet's never looked better. You talked about the relative value compared to the peer group and your higher netbacks. It would seem to point towards maybe buybacks would be an attractive option for you right here. Do you have any restrictions on buybacks in terms of the bank agreement or anything that would limit activity around a buyback? You want to take it, Gary? Since the bank loan is with the U.S. entity and the buybacks are on the Canadian entity, we have limitations on when we can send money to Canada, essentially, for the buyback. So there are some limitations. When we are wrapping up on CapEx like we are now, it makes it more difficult to send money there. That is why we have to time the buybacks. Oh, okay. That is why we talked about the second half of the year, mainly fourth quarter to maybe punch out the buybacks a little bit when we have some availability of cash. Got it. We do have a question around your guide. Can you talk a little bit around puts and takes around what would get you to the lower versus higher end of the range? Well, I'll say the biggest fluctuation is let's see how these wells do. Yeah, fair. So even internally as far as I get questions like, "When can we start drilling again?" Everything else. But it's like, let us get some more information to know where that is. Aside from whether oil might be $70 tomorrow or $120 number, right? But based on the full year average of WTI now would be above the range you gave. Yeah. Yeah. The pricing's definitely positive. The production also, the timing of the production, it's hard to forecast that. Yeah, of course. That would impact on the maybe the other side potentially. Got it. I know typically, and you'll change it, but we do have a question in regarding oil pricing being above even where you guided in June. Does that change the way you and the board might think about the pace of future development? Yes. The oil market right now is just so volatile, right? Yeah. We try to take a conservative approach on that. When we picked the 70, it wasn't trading at 70, it was trading higher than that. Right. Our fear was that it would drop. After we announced that, then I think a week later it was down below that for a few days. Yeah, you're absolutely right. Until it took back off again, right. So right now we're in very interesting times where you have such a dichotomy of what forecasts are for oil and gas that I'd rather err on the conservative side of things and get set up to like, we're going to have numerous discussions over the next couple of weeks for numerous areas where we want to go if this happens or if this happens. Yeah. In the field, including additional False Caney wells. Where would we go next? Let's get those ready and get it ready to go so we could quickly move. That's the advantage. Being the size we are, we can hopefully adjust. That's right. And you did this year. Fairly quickly. Right. How much do you weigh the curve on that? Because that's the problem, right? Yeah. You can't hedge anything, right, for that. You can, but the forward curve still looks horrible. Right. You're kind of stuck in a situation where you don't want to overhedge anything. We hedge the minimum amounts that we need for the bank, and we have to do that with costless collars and deferred puts, so we gain on the upside still, right, so we're not capped very much at all. Luckily, we did that when prices were lower as well. So we have some upper caps. Okay. But nothing that impacts us too drastically. Got it. Scanning through, make sure we covered everything in the queue. Looks like we are there. We just got about a minute left. Any closing comments before we wrap it up today, Wolf? No. I think, hopefully all shareholders as all of us are anxiously awaiting to see how these wells do over the next few weeks and the months and really have high hopes for that Lovina well, and we'll see how it does. I'd love to have a new bench that we could go after and drill and make good economic wells that are as economic as our Caney wells. So we'll see. As a reminder for folks, you think we'll see some of these numbers when? Probably mid-November-ish for the Lovina or the False Caney, right around the time of our financials, plus or minus. Yeah. We got a lot of moving pieces. I know. The completions there and the waiting on frac crews a bit and things like that. We'll see the Clifton. How the well reacts as well. We'll see the Clifton Mack well before then. Yeah. In a number of weeks. It depends on how it flows back and how quickly we get stabilized rates. Importantly, the proved reserves report, which will likely, depending on the success of some of these wells, the Clifton Mack, which are not in proved right now, and the Lovina, which is not in reserves at all right now. Right. Yep. That's it. That will be for the year-end report for sure from Netherland, Sewell again. Excellent. All right, Wolf Regener, Gary Johnson, thanks so much for joining us today. Hopefully, everyone found it as informative as I did, and hope everyone enjoys the remainder of the conference. Thanks, Wolf. Thanks, Gary. Thank you. Thanks, everybody.