Hello everyone, and thank you for joining us during the Lytham Partners Fall 2025 Investor Conference. My name is Joe Diaz. I'm a Managing Partner at Lytham Partners. Today, Wolf Regener, CEO of Kolibri Global Energy, will be taking us through the company's corporate slide presentation. Kolibri Global Energy trades on Nasdaq under the ticker symbol KGEI. Let's get started. Wolf, welcome. Let me turn the floor over to you for your presentation. All right, thank you, Joe. Appreciate the introduction, and thanks to everyone for participating today. I'll go through our presentation here. Normal forward-looking information, disclaimer statements, disclaimer non-GAAP statements, etc. You can find all these on our website under our corporate presentation that you can download there, which is at kolibrienergy.com. We are an oil and gas producer. In Oklahoma is where our production is. We operate the Tishomingo Shale Oil Field. We're drilling wells and producing wells out there through horizontals. We drill down to a vertical depth between, oh, 8,500 ft to about 11,000 ft and then drill horizontally, anywhere from, we used to drill mile-long wells. Now we're drilling 1.5 mi-2 mi wells. I'll go into why that's involved that way. Financially stable organization that we try to run, keep our debt low. We've had really good cash flow growth, and we continue to anticipate having the same. We have very high netback production, how much we make per barrel of oil that we pull out of the ground. We're fully funded for our 2025 drilling program through our existing cash flow and our existing line of credit. We have a $65 million line of credit with a bank consortium led by Bank of Oklahoma. It's a $65 million, and generally we have about $30 million roughly drawn on that. It fluctuates up and down as we drill wells, and then we pay them back again once we have that capital expenditure out and the production from those new wells, including their existing production. At the end of the year, we're forecasting to be around $30 million as well. We have a nice high-quality asset, about 40 million barrels of oil equivalent in approved category, 53 million in the approved probable category. Our approved reserves are split between approved undeveloped, meaning that hasn't been drilled yet, but we use Netherland, Sewell, a reputable third-party engineering firm, to do our reserves engineering. These are their numbers from the end of last year, so it doesn't include the wells we've drilled this year. They split our reserves between approved undeveloped of having 78%, so you can see how much in reserves are still available to be drilled, and 22% was in the approved developed producing category. Last year we approved our, or increased our approved reserves, I should say, grew them by about 24%. We drilled some what they call probable and possible categories and moved those into the approved category. As Joe said, our ticker on Nasdaq is KGEI. We also trade on the Toronto Exchange under KEI. Our Nasdaq listing is relatively new. It's been a couple of years because we were only traded on the TSX before that. This last year, we also qualified, actually a few months ago, for the Russell 2000. That was a nice milestone for us. We have just over 35 million shares outstanding. At roughly current prices, this was from a little bit ago, our market cap was $193 million. Our net debt, as I mentioned at the end of last quarter, was $27 million, but call it around $30 million in general that we have. That gives us a nice enterprise value of about $200 million U.S. Our debt to EBITDA is well below one. It's 0.64. Our reserves that I mentioned, Netherland, Sewell doing our reserve report at the end of last year, our approved reserves of that 40 million barrels of oil equivalent had a value of $535 million. That compares to our market cap of just under $200 million, right? You can see why we believe that there's a lot of growth left for this company. Our approved and probable reserves were close to $700 million. Those were at oil prices that were a little higher than where we are currently, but in the long run, I think we should be in that same range, and that'll be that value. Hopefully we'll continue to grow that value further. You can see our stock price history, ups and downs with oil prices, and also through this time period, we didn't drill any wells, and that's what happens when an oil company doesn't drill wells. Once we started off again drilling wells, we've had really good success. We had just defined the borders of the field. The core of it, we started drilling in 2022 again, had some great results, and that's what's caused the market to start recognizing our value, even though I don't think we're there yet. A little history of the company. We are, as I mentioned, in Oklahoma. We're about halfway between Oklahoma City and Dallas. We originally drilled for what's called the Woodford Shale. We had drilled and participated in 40 wells. We had about 12,500 acres. You can see from this, from the Woodford reduction, we were only making about 15% oil. The balance was gas and natural gas liquids. We had drilled and participated in about 40 wells. Exxon, you can see in purple down here. Hopefully, you can see my cursor. I had been acquiring acreage all around us. We were the last holdout. We kept saying no to the price that they were offering. They finally offered us up $147 million through negotiations. We said, okay, we're willing to sell you that, but we want to hold on to the rights for these intervals that are above the Woodford, called the Caney primarily, and there's also the Upper Sycamore. The reason for that is we had just drilled our first test well into the Caney. It was not economic by any means, but we thought it had potential in order to make economic wells in the long run. They didn't want to pay us what we felt it was worth. We're the only ones that were able to hold on to these upper intervals when Exxon bought everyone else out. We had about 12,500 acres, as I mentioned at the time. We have grown that to 17,000 acres, and that's what we've grown our reserves now. Those are all Caney reserves, grown those to 40 million barrels. Now our production is about 70% oil, the balance being natural gas and natural liquids. If you look at this, our liquids production is around 85%. A lot of companies just talk about their liquids production. We talk about our oil production plus liquids in general, just because we have so much oil production. It really transformed us from a natural gas producer into a liquids-rich producer. Our 2025 development program, as I mentioned, fully funded for gasoline production growth of 29%- 47% over 2024. We'll probably be at the lower end of that number. We have successfully drilled and completed 4.5 mi lateral Caney wells called the Lovina wells. We brought those on production, and those are producing 82% oil. I talked about the blended that we had is 70% oil. The Lovina wells, they're actually even oilier. They're 82%. We expect those to have a bit lower decline rates than our average wells we've had in the past. We also drilled and are in the process of testing what we call our East side well, the Forguson. That's in the process of being tested. Our last press release was it was making about 160 barrels of oil equivalent a day. This is in an area of the field. I have a slide on this that is not in our reserve report at all. This is potential upside. Like I said, I'll go into that in another slide. We're also in the process of drilling two more 1.5 mi lateral Caney wells called the Barnes wells. Our plan is in October to be completing those two 1.5 mi lateral Caney wells, along with two previously drilled 1 mi lateral Caney wells called the Velin. Our guidance for the year is basically up. Here's our adjusted EBITDA from 2021 of $6.5 million. Excuse me, end of 2024, our year was $44 million. This year we're looking at a $58 million- $71 million. As I mentioned, we'll be on the lower end of it because we were using $70 oil. We're expecting production to be increased, but probably on the lower end of our production guidance. Still great increase though. Our adjusted EBITDA, as I mentioned, the $58 million- $71 million is the range that we gave out. Capital expenditure of $48 million- $53 million. If we even caught our midpoint of $50 million of CapEx with an adjusted EBITDA, even the low end of $58 million, we're looking at having excess cash flow. What we've done is we've been buying shares back. We just renewed our share purchase buyback program. We've picked up around over 500,000 shares at about $5.20 U.S. to date. Production order by quarter basis, you can see it's been increasing nicely. Whenever we fracture stimulate wells that are close to other wells, we shut those other offsetting wells in for production, shut in their production, or the fracture stimulation. For the Lovina wells that we just fracture stimulated, we did the same thing in the second quarter. That's what you see the production drop. Obviously, there's a decrease from the high production rates that we brought on the wells here, which is natural, but this is a little lower than it normally would have been because we shut in those wells. Those wells are coming back on again in third quarter, along with the Lovina wells that were coming on production in the third quarter as well that we already announced. Same with the operating net income. You can see it's going up nicely. The red line here is our blended barrel of oil equivalent pricing. You can see even though prices have come down from the peak where they were in basically 2022, our net income has been going up. The same reason here, this drop is a little harder than it would be just because of the shut-ins and doesn't include the new wells coming on the Lovina wells. The Lovina wells, by the way, combined rate was about over 2,000 barrels of oil equivalent a day. You can see it'll make a big impact. Infrastructure is all in place out here. We owned about 1/3 of the gathering system when we sold to Exxon. That 1/3 became theirs. Now we're less than 1 mi from the gathering system. We worked out a deal with them that we can go into their gathering system. All the gas and the wet gas, as it's called, that transfers into natural gas and natural gas liquids is handled by Exxon. We pay a gathering and a compression fee to them. Oil is priced at WTI less $1.85 a barrel. That has been very consistent over the last six, seven, eight years. We don't have a big basin-wide differential that in some basins fluctuates a lot. That's been very consistent that it's close to WTI. Netherland, Sewell, our reservoir engineer at the end of last year, indicated that we had 52 approved locations left to drill, 31 probables, and 21 possibles. What's different this year is these are mainly 1.5 mi and 2 mi laterals. If you think about it, if you had two 1 mi laterals on top of each other and now it's a 2 mi lateral, it turns into one well, right? It drops your number of drilling locations down. We still have a lot of drilling locations in these longer length laterals. About 17,000 acres, as I mentioned, net to us. We have 41 Caney wells on production. The nice part is our acreage is 99% held by production. What does that mean? A deeper Woodford that we mentioned before that's developed by Exxon and we had sold to them is holding the leases for almost all of our acreage because our Caney wells are above that, our Caney zones that we're producing from and drilling for. It gives us the flexibility to drill where we want to drill when we want to drill. On top of the Caney that we have in our reserve report, we have this 3,000 acres on the East side. That's potential upside. We also have two other intervals that are between the Caney and the Woodford that we have the rights to. One is called the T-zone that we have placed a couple of wells on and that have been productive. Every once in a while, that has interfered with our Caney production. We decided to first drill and complete the Caney wells. When those have declined down to a certain level, then we feel we can go in, drill the T-zone wells. That way, if it interferes with the Caney, it's not a big impact. In some intervals, in some areas, it will or it may, and in some intervals, it won't at all. There is what's called the Upper Sycamore formation that other operators in the area to the North of us are exploiting right now successfully. We are looking to see where on our property we might be able to exploit that as well. The East side that I mentioned, 3,000 net acres to us. All the infrastructure is in place out here as well. Gathering systems are close in. The acreage, as I mentioned, is not in our reserve report other than it's listed as a contingent resource. That means it's not an approved or probable or even possible category, so zero value to it. The Caney itself out here has similar characteristics and thicknesses, just like the heart of our field, but it is shallower. We were sure we were going to make it well out here. We just didn't know what the economics of it would be. What oil price or what gas price would it take in order to make it economic? That is really what we're trying to figure out. We are the operator of this well that was successfully drilled and completed. It is 1.5 mi lateral. A large integrated oil company is our partner in the well. They participated for their working interest that they had remaining in the Caney. We are still in the process of evaluating whether this well will be economic at what oil prices. It will take another month or two. As I mentioned, 160 barrel of oil equivalent a day. It was still cleaning up. We only had about 2.5% of the fracture stimulation fluid back when we were reporting that rate. Normally when we get to 7%- 10% recovery is when we know we really have the maximum rate on the well. We also will want to see what the decline rates are. Drilling efficiency has gotten better and better at drilling these wells. You can see back in 2016-2017, it was taking us about 30 days to drill these wells. This is drilling days. This is the depth. Remember, we're drilling down to between 8,000 ft and 11,000 ft and then going horizontal. Our wells are total depth, total length that we drill, somewhere between 16,000 ft and some of them, they're deeper at 18,000 ft even. It was taking us about 30 days to drill down and horizontal for 1 mi. The last four wells we drilled for the 1 mi laterals, it was about $5.5 million each. The forecast going into 2023 was for $7.2 million. You can see the last wells we drilled in 12 days. That is what the big cost savings was out here. Plus, we've gotten better and better in completions. The first 3.5 mi laterals that we drilled were drilled in an average of 14 days. The Lovina wells were drilled in an average of 10.5 days. If you think about it, even if you average this out of going back to 12 days for the 2024 wells, now we're drilling 50% more lateral. We have 15% more access to the reservoir in the same amount of time that we were drilling just that 1 mi lateral. The Barnes wells are now estimated at a cost of about $7.2 million, which is the same as what we were forecasting our 1 mi laterals to cost a few years ago. That includes the price increases that we've had through casings and other material costs lately. Internal rates of return. What we've done is in the heart of the field, Netherland, Sewell has identified two types of our general, two types of locations, one that are a little gassier and one that are less gassy. We said, okay, as oil prices came down, everyone should know if we can make economic wells or not. We plugged in just a fixed oil price to their estimated production and what it would take in order to calculate what our internal rates of return are at various prices for the two different types of wells out here. This was at a $6.5 million well cost. I'll need to update that for the $7.2 million, but it gives you a general idea. We can make a lot of money still even at a $60 million-$65 million well price. Operating expense per barrel of oil equivalent, again, operating efficiencies. How much it takes to lift a barrel of oil equivalent out of the ground. These are 2024 annual financial numbers from other public companies that we consider our peers. You can see we're at the lower end of operating expenses per barrel. The ones that are around us are mainly natural gas producers. Natural gas flows out of the ground without a lift mechanism. You can see how efficient we are, even though we're an oil prep company mainly. That leads us to operating netbacks, how much we make per barrel that comes out of the ground. You can see that we're in the upper end of the companies that make the most money per barrel of oil equivalent coming out of the ground. When you look at our year-end reserve report from last year on a per share basis that works out to be $15 a share, we're probably at $19 a share in U.S. dollars. On September 15, a little while ago, we were trading around $5, in the $5.40, $5.50 range type of thing. You can see how much value we believe that there's still left here for us. G&A costs have been coming down nicely. Yearly net revenue has been going up every year. For our forecast number, that's kind of the midpoint that we picked there. A little bit on us, management team, myself, over 36 years of oil and gas experience, lots of operations experience, land acquisition, financing, selling projects, and generally running oil and gas companies. Gary Johnson, our CFO, 34+ years of accounting experience, 22 of those years in the oil and gas business. For instance, he was the Director of Technical Accounting for Occidental Petroleum. Dan Simpson, our Director of Engineering, has over 30 years of experience in oil and gas engineering reservoir work all around the world. Allan Hemmy, Senior Geologist, has over 15 years of experience in oil and gas. Our Board of Directors, our Chairman, has lots of oil and gas analyst experience in the U.S. For instance, one of his last jobs was at Jefferies, where he was the Managing Director of the Leverage Credit Trading Group. Doug Urch, our Chair of our Audit Committee, has been CFO of multiple oil and gas companies over his career. David Neuhauser, who owns a big chunk of our stock, owns almost 16% of it through Livermore Partners that he runs in Chicago. He has lots of capital markets experience. Leslie O'Connor, our Director, is now retired, but also a reservoir engineer, was running the Denver offices of MHA Petroleum Consultants and Sproule for a number of years. That really brings us to the summary. Traded as KGEI on Nasdaq, KEI on the TSX, good reserves. We're an efficient operator, both on operating expenses and drilling costs, keeping our debt low, just trying to do our business the right way. Have a lot of drilling inventory left. We've got a great team that we put in place, which is demonstrated by the operatorship that we've been very efficient. Increasing cash flow. We've got catalysts coming on for new wells that are coming on and the testing of the East side. We've been buying back shares in the company, looking to continue to grow the company, both through internally, but we're also looking at other external acquisition potential. It just has to be creative. We have been looking at lots of things for a number of years, haven't found anything that fits the bill yet, but we're still kicking tires and seeing if we can't find something that makes more money for the shareholders. We are all aligned with everyone on that front. That is it. I don't think it's too complicated of a story. I appreciate everyone's time here today. As always, if you have any questions, feel free to reach out always. Thank you very much. Joe. Wolf, thank you for that presentation. Lots of efficiencies. There are catalysts and opportunities ahead. That's exciting to see. We want to thank everyone for watching here today. If you have any questions or would like to schedule a meeting with Kolibri Global Energy, send us an email at 1x1@lythampartners.com. Again, 1x1@lythampartners.com. If you'd like to learn more about Lytham Partners, you can visit our website at lythampartners.com or follow us on LinkedIn to stay connected about future events. We hope you enjoy the rest of the conference and have a great day. Wolf, again, thank you so much. Thank you, Joe, and thank you everyone.