Hello and good afternoon, ladies and gentlemen. Welcome to today's virtual non-deal roadshow. My name is Julia Perron, a virtual event moderator here at Renmark Financial Communications. On behalf of our team, we'd like to thank everyone in New York and surrounding areas for joining us today for the presentation of Kolibri Global Energy, trading on the Toronto Stock Exchange under the ticker symbol KEI and on the NASDAQ under the ticker symbol KGEI. Presenting today is Wolf Regener, President and Chief Executive Officer. Joining us for the Q&A will be Gary Johnson, Chief Financial Officer and Vice President. The presentation will last approximately 20 to 25 minutes and will be followed by a formal Q&A session for which you can participate in using the chat box in the top right-hand corner of your screen. With that, I will hand it over to Wolf. Hi. Thank you, Julia, and thanks everyone else for joining us today. Let's go through these forward-looking informations, the disclaimers, non-GAAP measure disclaimers, et cetera. These can all be found on our website under our corporate presentation as well. Kolibri Global Energy, we're an oil and gas producer, producing oil and gas in Oklahoma from our Tishomingo Shale Oil Field. We try to run our company in a very financially stable fashion, keep debt low. We've had really good cash flow growth over the last few years and looking to continue that. We have high netback production, fully funded for our 2025 drilling program with cash on hand in the existing line of credit. The plan is for the same thing for 2026, even though we haven't put our forecast out yet for that. We have a line of credit with the Bank of Oklahoma, who's the syndicate lead of $65 million. We have what we consider a great asset with very high-quality reserves, proved reserves of over 40 million barrels of oil equivalent, and proved probable reserves of over 53 million barrels of oil equivalent. In our proved reserves, you can see our split. This was at the end of last year. About 22% was in the proved developed producing category, and the balance was in the proved undeveloped category. That has changed a little bit because we have drilled wells this year. You will see that proved developed producing percentage go up in next year's reserve report. In 2024, we increased our proved reserves by 24% by drilling some of those probable and possible reserve categories that move that into the proved category. Company information, as Julia said, we're on the NASDAQ under KGEI. We also trade on the TSX under KEI as a ticker. Share price running around $4. It's come down quite a bit here with the oil prices that have been reduced. Have about 35.4 million shares outstanding, gives us a market cap of around $145 million US. With our net debt at the end of last quarter, it was $42 million. So enterprise value about $188 million, roughly. Debt, as I mentioned, we keep that down relatively low. Our debt to adjusted EBITDA, excuse me, is right around one. That'll actually come down next year. We're planning on reducing the debt a little bit further in first quarter. Our reserve report at the end of last year, our proved reserves of that 40 million barrels of oil equivalent that I mentioned was $535 million. Now that is at oil prices that are about in the mid-70s, and we're trading 58-60 right now. That'll be a little bit lower, but you can see that's quite a bit of valuation difference still between the two. History, as I mentioned, we're in Oklahoma. We're about halfway between Oklahoma City and Dallas. Originally, we drilled for what's called the Woodford Shale. The Woodford Shale here, the production you can see, was only about 15% oil. The balance was gas and natural gas liquids. We had drilled and participated in about 40 wells, had about 12,500 acres. We sold that to Exxon/XTO for $147 million back in 2013. You can see down here in the purple, they were acquiring acreage all around us, and we were the last holdouts. In that negotiation, we actually said, you know what, we just drilled a well into this interval that's just above it called the Caney. It wasn't economic yet, but we were producing oil from it, and we felt like we could make it economic. They didn't want to pay us what we felt it was worth. We held on to that. We're the only ones in this trend that were able to hold on to what's called the Upper Sycamore and the Caney, which are the two intervals that we have the rights to still. We've since grown our acreage position to about 17,000 acres. That's where our 40 million barrels of proved and 53 million barrels of probable reserves have come from. As you can see now, we're at 66% oil in our production from last quarter. Actually, September's mix was up to 71% oil. We drilled a couple of wells last year that were a little in the gassier area. This year, our previous wells we drilled are oilier again. Our production mix has come back up again to a higher level on the oil side of things. 2025 activity, what we did, it was just basically a continuation of the field development. In the second quarter, we had drilled four mile and a half lateral Caney wells. These wells, I should say, we're going down between 8,000-11,000 feet. We're going horizontal. In the past, we were only going horizontal by about a mile. Now we're going horizontal by a mile and a half, and we'll be drilling as much as two mi laterals as well. We completed those wells, brought those on production, and those were producing about 82% oil. That is why our production mix has come up again to that 71% in September. We also drilled a well on what we call the east side, which is not in our reserve report. It is just listed as a contingent resource. I have got a slide that goes into that a little bit further. We are testing that right now. We are in the process of completing four wells, two more Caney wells that we drilled this year in the third quarter, fourth quarter. We are bringing those on along with two other wells that we previously drilled, all in the Caney. Those are expected to come on production in December. That leads us to our guidance for the year, average production of 4,000-4,400 BOE a day, which is a 15%-27% increase over last year's numbers, adjusted EBITDA, even with lower pricing. We're expecting 4%-14% increase. We'll obviously depend on pricing for the rest of the year as well. CapEx of about 55 million-58 million. Our adjusted EBITDA, you can see over the last few years how well that's grown. It's growing here, even with oil prices lower. With the excess cash that we've had, we are buying back shares in the market. We've bought back about 570,000 shares out of the market, and we'll continue to buy some shares back out of the market. Production growth on a quarter-by-quarter basis. You can see how that's been growing up nicely, steady growth increase. Same with net operating income. The blue line is our net operating income. The red is the barrel of oil equivalent prices that we've received. You can see even though prices have come down, our growth on net operating income has still continued to increase. With the new wells coming on production in fourth quarter, you can expect that to be increased as well, assuming those all go well. All the infrastructure is in place in the field. We do not have any large infrastructure projects we have to do. When we talk about our well costs, that's all in facilities hooked up, everything else. There are no other big infrastructure costs that we have. Oil is priced at WTI, West Texas Intermediate, less about $1.85. Netherland, Sewell & Associates gave us 104 additional locations that we could drill at the end of last year. 52 of those were in the proved category, 31 probables, 21 possibles. Those are now mainly mile and a half and two mile laterals. As I mentioned earlier, in the past, we were just drilling one mile laterals. These are now mile and a half and two mile laterals. We have to drill fewer wells to get the same reserves. It is more efficient. We brought our acreage, as I mentioned, to 17,000 acres. We have 41 wells on production with four more hopefully being on here in the next few weeks. The acreage is 99% held by production. In addition to the Caney, we also have additional upside from the east side that I will have a slide about, the T Zone and the Upper Sycamore formations. The upside potential, east side acreage, is currently classified as a contingent resource. We drilled the Ferguson well where we're the operator, and we have a 46% working interest. The balance of the working interest is by Exxon that participated with us. We have about 3,000 net acres out there. It is classified as a contingent resource, as I mentioned. Characteristics are very similar to what we have in the heart of our field, except for it's shallower. We knew it was going to have a little less energy. We're waiting on the final results from that. It's producing not at huge rates. It will have to take a little longer to see when we get the fracture stimulation fluid off if it increases production further or if it just flatlines. Like it looks like it has been recently. It's been quite flat. We will figure out what kind of oil prices we need to drill additional wells out here. It doesn't look like it'll be economic at $60 oil. We'll need higher oil prices from the early stages here that we have. There's also the Sycamore interval in here that we have the rights to. We have the rights to the Upper Sycamore. Operators to the north have made successful Sycamore wells. Our team has been refining additional locations to possibly test it on our property as well because it is present over the entire acreage block. The T Zone formation that people kind of have forgotten about is a proven productive interval. We have decided not to produce it yet because we did fracture stimulate up into the Caney in one of those locations. Once the Caney is fully exploited, we have it all drilled up and we have produced a certain area for a while, then we can go in and drill some additional T Zone wells. Those are not in the reserve report yet. There are no proved undeveloped locations credited in the reserve report for the T Zone. Drilling efficiencies—we have gotten better and better drilling wells over the years. Back in 2016, 2017, it was about 30 days to drill these wells for one mile laterals, I should say. In 2024, we had it down to about 12 days. That dropped our well cost. In 2023, we were going in expecting a $7.2 million well cost for a one mile lateral. We actually completed those last four one mile laterals for $5.5 million each. Since then, we've drilled additional mile and a half laterals. The first three were drilled in 14 days. The Levinette wells, which were also mile and a half laterals, were drilled in an average of 10.5 days. The Barnes wells that we just were drilling just now and that we're completing now have a budgeted cost of 7.2 million. You can see, even with some cost escalations that have happened in the industry, we're drilling mile and a half laterals for 7.2 million now, which was the same that we were expecting to drill one mile laterals. That means we have 50% more access to reservoir, hopefully 50% higher rates from these wells for the same price as we were drilling one mile laterals a few years ago. Internal rates of return, what these wells can produce. These are curves based on Netherland, Sewell, what they expect a higher gas area well in the heart of our field to produce, and what the lower gas rate, higher oil percentages would be in some of these areas per Netherland, Sewell's decline curves of what they estimate these wells would do. We just ran those numbers based on fixed oil prices. Just to show that at $60 oil price, we're making really good rates of return still. This was 50-117% rates of return. We do have to drop those curves down a little bit because our well cost, we're estimating now at 7.2 million versus the 6.5 million. You can see we can still make good rates of return assuming they perform along the lines of what Netherland, Sewell expects, even at a $60 oil price environment. That's why we didn't stop our drilling program this year. We can continue to drill additional wells next year as well. Operating expense per barrel, part of what makes us money and helps on those returns on the previous slide, is how inexpensive it is for us to get oil out of the ground. Our operating expense per barrel of oil equivalent, these are peer companies taken from 2024 annual financials along with ours as well. You can see we're at the lower end of operating expenses. Some of those that are around us are mainly natural gas producers where gas just flows out of the ground naturally, whereas oil has to be lifted out of the ground. That also leads to netback, how much we make per barrel of oil equivalent. We're same thing on the upper end of these same peers of how much we make per barrel of oil equivalent. We're right in there with the best operators that are out there. G&A costs have been coming down nicely. Yearly net revenue has been growing nicely. A little bit about us, management team. I have over 36 years of oil and gas experience, everything from land acquisitions to lots of operations experience, finance, and just generally running oil and gas companies through multiple different companies and selling them as well. Gary Johnson, our CFO, years of accounting experience and 22 years in the oil and gas space, including part of his career with Occidental Petroleum. He's got a Bachelor of Science in Accounting and an MBA from Auburn. Dan Simpson, our Director of Engineering, over 30 years of engineering experience, petroleum engineering experience, I should say, all around the world. He's been great. He's come on full-time with us here about a year ago, even though we were working together with him for a number of years before that. Alan Hemi, our Senior Geologist, has over 15 years of oil and gas experience and is doing a great job. Our board of directors, I like to say we kind of tick all the boxes in my belief. Evan Templeton is our Chairman, years of analyst experience in the oil and gas space, including last stint was Managing Director in the leverage credit trading group at Jefferies. Doug Erch, CFO of numerous oil and gas companies in his career, he's the Chair of our Audit Committee. David Neuhauser runs Livermore Partners, who is a large shareholder in the company and brings lots of capital markets experience to the table. Leslie O'Connor, director, lots of engineering experience where she used to run the Denver offices of Sproule and MHA Petroleum Consultants, which are reservoir engineering firms. That's kind of the summary. Bring us to the summary slide. Ticker KGEI on the NASDAQ. We're an efficient operator, low debt. We've got other additional upside, lots of drilling inventory left in the Caney, but also upside in some of these other formations. Have a good working relationship with our bank, $65 million line of credit in place. We joined the Russell this year. We're doing shareholder returns to the company. The oil and gas business is volatile price-wise. Even when we are down lower prices-wise where we are here, we are still making money and no issues with going forward here, barring anything really unforeseen. That is about it. Thank you all for the presentation and welcome, Gary. We will now start the Q&A for today's presentation. Your first question for today, a viewer commented, "Production jumped 40% year over year, but netbacks dropped 23%. How sustainable is the production growth if pricing remains soft?" I mean, when we drill wells, there are declines, especially in shale. The newer wells decline harder than our existing shales, but we are building up a good base that has a lower decline rate than just the new wells coming online. New wells, some additional wells are coming online right now or will be in the next month. That will add to our production base as well. We would have to continue to drill wells in order to keep production at some flat level next year. As you saw from that graph, assuming that the wells perform like Netherland, Sewell, which is a very reputable oil and gas engineering firm, as long as they perform along those lines, then we can make good money still even in the $58, $60 oil price scenario. Excellent. Thanks for shedding light on that, Wolf. Your next question, a viewer is asking, "Does KEI have a contingency plan if commodity strip weakens by 10-15%?" Yeah, I won't put a number on it, but if oil prices drop further, then we're small enough where we can adjust whether we drill more wells now or whether we hold off for a little while. Even in this price environment, when we're still making $30 plus a barrel of oil equivalent, and basically our blend of oil is going up higher, our percentage oil in our blend, so that makes us more money as well. We're actually in really good shape even if prices drop further that we can ride out the storm, so to speak, and not get ourselves in trouble. We're not over-leveraged. Our financials, I think, are in really good shape, and we have a great property that makes money at even low prices. Thank you for elaborating on that. Your next question is, "Can the production growth continue at a similar rate?" That's just going to be dependent on how many wells we drill. So Netherland, Sewell & Associates gave us credit for 50-plus proved locations. We think some of those probable locations are going to slip into the proved category as well in the future. We do have a lot of running room in that. We have got other intervals like the Sycamore, for instance, that we think have a lot of potential, especially with some of the operators drilling good wells offsetting us to the north. I think we have a lot of room for future growth as well. Excellent. Thank you for your comments on that, Wolf. Moving on to your next question, viewers asking, "Do you expect production of oil versus natural gas percentages to remain the same in Q4?" Hopefully, they will be better than the third-quarter average because in September, we were already up to 71%. Then when we bring these new wells on that we expect to be in the higher oil percentage range, that'll hopefully add to that as well. That is where I think the mix of our percentage oil should be increasing further over the 66% up into the low 70s at least. Yeah, I think we're at 67% for the nine months, so that'll go up. I mean, it'll take a little bit of time to go up as the Levinette wells kick in, but it'll definitely go up from there. Excellent. Thank you both, Wolf and Gary, for your responses. Your next question, a viewer asks, "Will the remaining four wells come online at the same time in December?" Yes, they will all come on at the exact same time. Oh, it appears we lost you, so hopefully we'll be back soon. I'm not sure what happened. Technical error, I'm sure. When it just popped off, like we lost internet connection. But yeah. So we do fracture stimulate all the wells, and then we have to drill out the plugs after that from the fracture stimulations, and then we'll bring those all on at the same time. Excellent. Thank you, Wolf. Oh, I see Gary is back. Apologize to our viewers for the technical difficulties. Welcome back, Gary. We're sorry about that. Let's continue with the Q&A. Your next question is, "Does Exxon have any say in whether or not the Ferguson well and any subsequent wells drilled on the east side acreage are economically viable or that's solely up to Kolibri?" Yeah, in Oklahoma, it's solely up to the operator. So we're the operator of that section. are other sections that they may have more of a say in, but there are a number of sections out there where we have a say where we can propose wells. They can propose wells as well. It is just a matter of who is the operator. Thank you for clarifying that, Wolf. Your next question, a viewer asks, "How many wells are currently planned for your 2026 drilling program?" We have not announced what our 2026 program is. That is the flexibility that I kind of alluded to earlier when we put our forecast together and what we propose to the board. We will see what we think oil prices are, where they are currently, etc. We will be set up with numerous locations where we can drill wells and we can move to them quickly, even if we do not drill anything right away. We try to put that flexibility in. We don't have any long-term contracts, and there are drilling rigs around and available right now. I don't see any issue with waiting for the drilling rigs where we can change gears pretty quickly. Thank you for your response. Your next question, a viewer commented, "What is management's long-term vision for the Ferguson 17-20-3H well? And how would a strong production outcome influence management's approach to its current 46% working interest in the surrounding land package?" We will evaluate how that well does in the end. If we can show that it's economic at whatever prices we think are in the future here, then we would definitely propose drilling more wells and drilling more wells in that area. There is also the Sycamore's potential out there as well. It is just an ongoing evaluation that we will see what happens. At that $60 oil price, I do not see that being economic right now. But at higher oil prices, assuming it holds in there or hopefully increases some more, we will see. Excellent. Thank you, Wolf. Moving on to some of the financial questions we received from our viewers today. The first one is, a viewer commented, "Adjusted EBITDA rose modestly despite higher production. How much of that improvement is volume versus cost control? And what are the key cost items you expect to change over the next 12 months?" Gary, you want to take the first part or do you want to? I mean, cost went down. I mean, the prices went down too, so that kind of offset the production increase as well. I think we are still expecting it to grow a little bit even with the prices being lower. That is why we adjusted the forecast to the price decline for the year. Yeah. Really, it is a volume increase that helped us here while oil prices came down quite a lot, right? We will just see what happens as we go forward. We do have some cost savings, but we are pretty low on the cost per barrel of oil equivalent as we are pulling it out of the ground already if you look at the comparison slides. We do have some ideas to save some further costs, but really, I think we are doing a really good job of getting oil out of the ground already where it is. If you are looking at $7-$7.50 oil price or cost for getting oil out of the ground, we have got a lot of room to go. Excellent. Thank you both for your comments on that. Your next question is, "How is the company thinking about hedging and oil price exposure given the recent deadline in realized prices? Do you have a plan to protect cash flow if prices stay lower?" We have a certain amount of hedges in place already. Part of our bank line is they require us to put hedges in place. Mainly in the last year and a half or so, we've been putting in place what are called costless collars. It does not cost us anything, but it gives us a floor, but it also gives a ceiling. When oil prices dropped like they are recently, what we did was we just put in what we call puts. It protects on the downside, costs us a little bit per barrel, but it leaves the upside potential there in place. We are not over-levered. We had mentioned earlier that in the first quarter, we're planning on reducing our debt by another $8 million-$10 million because these wells are coming online late in the year here. We'll have a lot of benefit for that early in 2026. That is really how we kind of try to handle that. Thank you for your insight on that, Wolf. Your next question, a viewer asks, "How does the company prioritize debt reduction versus continued growth capital, particularly if commodity prices remain soft into early 2026?" That is the big question. That is the decision that is going to be a robust board call, I'm sure. As I mentioned, Gary and I will put together what we believe the company should do, and then we'll discuss it with the board. It will depend on where prices are. The lower prices are, probably the less number of wells we're going to be proposing for next year. The higher they are, the more wells that we anticipate proposing. Being the size we are, we can be nimble, and that's the one big advantage that we have. Understandable. Thank you, Wolf. Your next question is, "What's the average cost per completed well this year?" Our budget, which is the most recent that we put out there, is $7.2 million for these mile-and-a-half laterals. That's all in with including facilities and everything, so. Excellent. Thank you for confirming that. Your next question is, "What does CapEx look like for 2026, and will it require additional credit draws?" What we are planning on doing is living within our cash flow. We use our credit line like we did in this year. We'll draw down when we're drilling wells, and then we'll pay it back when those wells come online along with our existing production. We just use it really to manage our capital expenditures because when we're drilling four or five wells at a time, you're laying out $30 million-$40 million. You lay that out using cash flow plus a bit of a line of credit, and then you pay that back down in order so you don't get over-leveraged. My plan would be to do the same thing if oil prices are lower. Again, drilling fewer wells, probably paying down more in debt, but we're also going to look at returning more capital to the shareholders as well. Excellent. Thank you for expanding on that. Moving on to your next question of viewers asking, "Can you go over the reassessed production tax adjustments? Is this a one-time adjustment, or will there be further adjustments in the quarters ahead? Yeah, I'll catch that. It's a one-time adjustment. It was just a reassessment of some costs that were through the last nine, ten months. So it's a one-time thing. Excellent. Thank you for clarifying that, Gary. Your next question, a viewer asks, For what reasons do you see oil prices going up? I think demand is holding in there pretty well, given barring a big recession. I think there's a lot of noise out there with oil on water, but that's just because that's how they're shipping more oil around now from Russia, etc. Even if the Ukraine war settles, I think all the countries are putting out everything they can put out right now. I think that's a little overdone. I think the headlines here the last couple of days, I've read some reports that they were a bit misinterpreted over what OPEC was saying, but they were talking about third quarter. Third quarter is behind us. Fourth quarter, they actually increased their demand on oil. I was actually surprised to see what oil did yesterday. That is the market. The market is volatile. I haven't seen the numbers this morning that came out from the U.S. side of things yet, but it's on a week-by-week basis. I don't think there's a big oversupply or as big as what everyone is fearing. I think oil is going to turn around and be in the high 60s, low 70s again in the not-too-distant future. I couldn't tell you if that's a week or six months. That is just the nature of this business. You have to prepare for it being lower, and hopefully, it's higher. Fortunately, there's no crystal ball, right? No, there's really not. Moving on to your next question. Do you have any idea why TFG has asked for the special meeting? They have not given a reason for it. We do know that they were upset about us filing the shelf in the US, which is very common. All oil companies and most companies in general have that in place. It didn't change anything we're doing. We just feel like the best thing is to have all options on the table because you don't know what's happening in the future or if you have a small transaction that you want to do that you can do quickly. We haven't done anything in years that hasn't been accretive. We've looked at a lot of deals, but never done anything. It was a surprise to us, but we do know that they were not happy about the shelf. Other than that, there has not been any comments. That is all we know. We do not think it is the right thing for the company. Thank you for elaborating on that, Wolf. Your next question, a viewer asks, "How does your valuation compare to peers in the area?" Valuations, peers in the area are either private or large companies. That is hard. We believe that we are undervalued if you look at our reserve valuations in general. That is the best thing I can speak to. We are a very efficient operator, so I think we should be valued higher than others. We have great reserves. We don't have big expenses on because we don't make a lot of water, so we don't have any big disposal costs and things like that. I think we're an efficient operator. We've got a great field, and I think we deserve a premium. I don't think we're trading at a premium right now, especially with where we're traded to. That's the nature of this oil and gas business. Oil prices go down, and people panic a bit, and stocks move lower, and then prices recover, and they'll go up. I have faith that we'll be higher in the future. Excellent. Thank you for your comments on that. We're coming up to your last three questions for today. Your next question is, a viewer commented, "You announced a normal course issuer bid. What size and pace of buybacks should shareholders expect, and under what price/market conditions would you pause or accelerate repurchases? We will continue to buy back shares. We bought back, I think, 570,000 roughly. Is that right, Gary? Yeah. Correct. Yeah. So shares. When it is advantageous to us to do so, when the price is lower, we would like to do more. We do have some sort of limitations from the bank that they put on us. When we spend a lot of money in the field, on the capital side of things, then we do not have the money to, as much money, I should say, to buy back shares. When the cash flow is higher, that is where we can use a higher percentage to buy back shares as well. For next year, bigger plans, we're allowed to, over the next year, buy back, I think it's 1.6-1.7 million shares. 1.7 million from the regulator point of view. That will be part of the discussion that I mentioned earlier with the board for next year, what our plans are, how much we allocate toward that, how much we allocate toward drilling, etc. That will be oil price dependent as well, obviously. Excellent. Thank you both. Your next question, a viewer asks, "In your opinion, how much weight do the ISS and Glass Lewis recommendations carry with your shareholders?" I hope a lot because they came out and said that they were against this proposal. We just announced that a few days ago when it seems they came out. We are hoping that it has a lot of weight. They are independent advisory firms. Excellent. Thank you, Wolf. Your last question for today is, "Considering all the wells you've drilled, which one has been the most productive?" That's hard to say. We've had a lot of good wells, actually. I don't know. I'll actually have to think about that. They haven't all been perfect, mind you, because it is an average. Yeah, there's a few that stand out. Some of the Glenn wells and some of the Levina wells, maybe some of our better wells in the end here, even though they didn't have quite as high as an IP rate, but that high production rate. If they have low decline rate, they may end up being really good. Yeah, that's a great problem to have. Thank you, Wolf and Gary, for all your answers today. Thank you to our viewers for submitting your questions. If you did not get a chance to submit your question, feel free to reach out to the appropriate account manager here at Renmark. This concludes our presentation for today. Before we go, I'll turn it back over to you, Wolf, for final remarks. Thank you. I just want to say thank you, everyone. Thanks for your support for existing shareholders and new shareholders. Please feel free to look into us further, ask questions. Thank you for spending your time with us today. Thank you again, Wolf and Gary, for the presentation. Once again, this was Kolibri Global Energy, trading on the Toronto Stock Exchange under the ticker symbol KEI, and on the NASDAQ under the ticker symbol KGEI. Thank you again to everyone in New York and surrounding areas for joining us today. The playback for this virtual non-deal roadshow will be available on our website 24-48 hours after the presentation under the VNDR Library tab. Stay tuned for other presentations in your area. Thank you, and see you next time.