Good afternoon, everyone. I'm Steve Ferazani, an Analyst at Sidoti. I can see the room is still filling in, so I'll give it a couple of seconds before I introduce the next presenter. But before that, I would like to remind everyone following the presentation, should it be quite informative, we will have some time for Q&A. If you do have a question, anytime during the presentation, you press the Q&A button at the bottom of your screen, type in the questions, and we're going to get to absolutely as many as we can, time permitting. Looks like the room's pretty much filled in now, so I don't want to take up any more time. So happy to be joined by Kolibri Global Energy. The ticker is KGEI here, also trades in Canada. We're joined by CEO Wolf Regener, CFO Gary Johnson. Wolf, let me turn it over to you.
All right, thanks, Steve, and thanks, everyone, for joining. For those of you that have seen this before, a couple of slides are new, but I'll just go through the whole deck as well. Forward-looking information, by the way, this can also be found on our website and our corporate presentation for both non-GAAP and other things. For those of you new to the story, we're an oil and gas producer, and we produce our productions in Oklahoma through the Tishomingo shale oil field, and we have a good amount of our proved reserves that are in the proved undeveloped category. These are kind of weird at this time of the year because our reserve report, the last one that was out, was at the end of 2024. Our new report for 2025 won't come out till near the end of March. So keep that in mind here.
We'll have drilled a bunch of new wells. We drilled nine wells in 2025. So you'll see this proved developed producing slice get larger this last year. Proved reserves in 2024 grew by about 24% because we drilled a number of probable and possible locations that we had on the books. We've had really good cash flow growth over the last few years. We try to run our company in a very financially stable fashion, keeping our debt down low. Our debt, basically all our drilling, will be based on cash flow. So we use cash flow to drill our wells, and we use debt, which is where I was going before, to manage our working capital. So when we drill a group of wells, it's a bunch of money going out.
We draw down on our line of credit, and then we use the production from those wells and our existing production in order to pay that back down. Our goal is to kind of be in the $35 million range, and we're about $42 million at our last reported numbers. We have what we consider a really good asset, and hopefully you'll see that as well through this presentation. 40 million barrels of proved reserves, 53 million barrels of proved probable, put together by Netherland, Sewell which is obviously a very competent reserve reporting engineering company. You can see we've had, stock price-wise, a pullback from the high. This was when we were going on the Russell 2000 last year as well, and then we've had a pullback as oil prices have dropped back down.
Share prices floating a tiny bit higher than this, but so call it $130 million market cap U.S. dollars. As I mentioned, just over $42 million in that debt at the end of third quarter. It was an enterprise value of just over $170 million. And then that compares to Netherland, Sewell & Associates' analysis, again, at the end of 2024 for that 40 million barrels of oil equivalents, $535 million. That is at oil prices that were in the $70s, though, right? So we've pulled back from that a little bit. But even if you discount this a bit for the lower oil prices, you can see there's quite a discrepancy still between what we're trading at and what that proved reserves is for. Our value at proved and probable is almost $700 million at the time. As I mentioned, we're in Oklahoma.
We're about halfway between Oklahoma City and Dallas, so if you're looking on a map for us here. Originally, we drilled for the Woodford Shale. The Woodford Shale was quite gassy. It was only about 15% oil, and the balance was gas and natural gas liquids. Exxon came in and was buying out everyone around us. You can see all the purple down here is Exxon. So we were the last holdout. We had just drilled one well into an interval called McKinney, which is slightly above the Woodford, and that well gave some promise. It was not economic by any means at that point in time. When we were negotiating with Exxon and we moved their price up to this $147 million mark, they didn't want to pay us anything for what we thought the McKinney would be worth.
They agreed to let us keep the McKinney and Upper Sycamore rights. And so that's what we've now grown into the valuation that we have. The 40 million barrels of proved reserves increased our acreage position from 12,500- 17,000 and really turned ourselves from a natural gas producer into an oil producer. Third quarter production was about 66% oil. Since then, we brought on some more wells in the oilier part of the field, and November's production mix was up to 75% oil, with the balance being gas and natural gas liquids. So on a liquids-rich basis, we're approaching 90%, basically. In 2025, what we did was we continued just developing the fields. We drilled four wells called Lovina wells that were a mile and a half laterals earlier in the second quarter.
In the third and fourth quarter, we tested a higher risk well that was on the east side that's not in our reserve report called the Ferguson. We also brought online in December four more wells in the McKinney itself, which is what is giving us a really good exit rate from the year going into 2026. The Lovina wells, as I mentioned earlier, had a much higher oil percentage, Lovina and Barnes, I should say, excuse me. That's what led us to move from a third quarter 66% oil mix to a 75% in November. Our guidance for 2025 was 4,000-4,400 BOE a day. The Adjusted EBITDA, keep in mind that this was at a $64 oil price, and obviously oil prices were lower than that. When we announce, we'll be down here low on the lower end.
Adjusted EBITDA, just on a reference point, year-over-year has been growing drastically up from $6.5 million in 2021 to $44 million in 2024 and about that same range in 2025, even though oil prices are drastically lower. We're also buying back some shares in the market. So we're entering 2026 with a strong 2025 exit rate. We intend to pay down our debt, which we announced, pay down some of the debt, I should say, in the first quarter. We're continuing to buy back shares, but we'll emphasize paying down debt first in the first quarter and then buying back shares even more aggressively in starting the second quarter. Our plan is to drill more McKinney wells this year. We have not put out a forecast yet for the year.
So the number that we're going to, how many we're going to drill, is yet to be determined at some of our board meetings. We're also planning for our first Sycamore well, which I'll go into on a different slide. And what we are doing right now in first quarter is permitting and building numerous different pads so we can drill, obviously, only multiple wells off the same pad because that's what we do. That saves money and it's more efficient, but in multiple areas of the field. So not only for what our plans are for the year, but also so we can quickly increase that if oil prices increase as well. Production, here's the growth on a quarter-by-quarter basis. You can see it's been up into the right nicely.
And then in December, our flush rate with the new wells coming online was over 6,000 barrels of oil equivalent per day. So you can see that's off the chart and that will decline. So don't forecast just straight that out for the rest of the year because these shale wells always do decline. But you can see that it'll be up here and to the right as we move forward. And that's how we're starting 2026. Operating net income, same thing has been going up nicely. The red line is the barrel of oil equivalent pricing that we've been getting. So you can see even when oil was up and has come down, our net income is still increasing. In the field in general, the infrastructure is in place. By infrastructure, I mean the gathering system. That's the main thing that we need an infrastructure for.
We're less than a mile from tying into the gathering system for our wells. Not that we make much gas or NGLs percentage-wise, but still we don't have a lot of infrastructure cost to take care of that. Our oil is trucked out of here. We get WTI less about $1.85, and that has been very consistent. It's not a big differential changes that have been happening year-over-year. It's been quite consistent at about $1.85 less WTI. Netherland, Sewell does our reserve reports, and this is at the end of 2024, gave us 104 booked locations. 52 of those were proved, 31 probables, 21 possibles. This last year, this was mainly mile and a half and two-mile laterals, which is what we're intending to drill predominantly. We have 45 wells on production.
I mentioned the 17,000 acres that we've grown this into, and 99% of our acreage is held by production. So that's from not only the wells we've drilled, but also from those old Woodford wells that Exxon still operates. So that holds all that. I'll go to the upside potential on top of this that we have. We've got upside potential from the most exciting one right now is from the Sycamore formation. There's some operators to the north that have made some successful Sycamore wells. We've been looking at the geology on that. We've always known that the Sycamore was there. And we have shows from old wells through the Sycamore that indicate that oil and gas is over part of the acreage, at least in the Sycamore.
So at some point in time, we will drill a Sycamore test well as well to hopefully unlock another horizon for us and add even more reserves and well locations to the bottom line for us. The T-zone formation is not in the acreage, is not in the reserve report either. It's an interval that we have put some wells into. We were trying to complete those at the same time as the McKinney a few years ago, and we found out in a couple of locations that the T-zone was actually impacting negatively the completions of the McKinney. So we decided to not at this time start developing the T-zone at the same time, but just focus on the McKinney.
What we'll do is when a McKinney area is fully developed and it's produced for a while and the production rates are lower, then we can go in and drill some T-zone wells to extra stimulate that. In the off chance that it fracks up into the McKinney, it's not as detrimental. Plus, it's just more like a restimulation of the McKinney at that point, but it doesn't interfere with the productivity of new McKinney wells. The east side is the Ferguson well that we spoke about earlier in a slide. That was a step out off to the east. It was in an area that the geology looks very similar to the heart of the field. We knew we were going to make a well. We just didn't know how much energy it was going to have because it was shallower.
The rates on that well were about 160 BOE a day, significantly less than what we expect from the heart of our field, so that's an area that we probably won't be drilling any more wells unless oil and gas prices are significantly higher. But again, it's not in the reserve report, and so that was just upside. What we believe in doing is drilling development wells and then occasionally taking something that's a little riskier and adding a well in on that in order to increase our inventory of drilling and add to reserves further. Drilling efficiencies, we've gotten better and better over the years of drilling wells. Back in 2016, we were drilling down between eight and 11,000 feet, by the way. That's where our property roughly is. It was taking us about 30 days to drill down at that level and drill a one-mile lateral.
By the end of 2024, we had gotten that time knocked down to about 12 days. So those four wells that were drilled at the end of 2024 were completed for about $5.5 million each for the one-mile laterals. The 2023 forecast for those wells, we were expecting it to be about $7.2 million. So you can see we saved a lot of money in being able to do that. The wells we've drilled that are mile and a half laterals in the McKinney, the first three in the Alicia Renee were drilled in about 14 days, and then the Lovina wells were drilled in an average of 10 and a half days. So right in that, if you average that out, in that 12 days that it was taking us to drill one-mile laterals. So obviously that's more efficient.
The Barnes wells were one and a half mile laterals at a budgeted cost of about $7.2 million now, with some cost escalations that have taken place over the last or take place in 2025. Touch on based on this a little bit. This is our internal rate of return table, which talks about takes the Netherland, Sewell two different types of well locations out in our field, a higher gas interval and a lower gas interval, excuse me, sorry about that, and a lower gas interval here. As far as we ran their number, the decline curves that they put together at a constant oil price to give us this. Now, keep in mind that we're spending a $7.2 million well cost now instead of the $6.5 million. So you need to shift these curves down a little bit, a little less higher rates of return.
But for instance, we put out that our four-pad Lovina well that we drilled in early 2025, where the costs were actually a little bit higher because we had really bad weather. It was right in the middle of a storm. They still generated a 33% or would generate a 33% IRR based on a $60 oil price. So even with a little higher costs on those wells, a little lower productivity than some of our other wells, we're still making a 33% IRR on those wells or expect to, I should say. And one of the reasons is our operating expenses. We're a very efficient operator out here. We're about $7.50 a barrel of oil equivalent of getting the oil out of the ground. And if you look down here, these are from 2024 numbers from annual reports from what we consider our peers.
You can see we're the lower end of that. And most of those down here on this end are natural gas producers where natural gas just flows out of the ground naturally where you don't have to lift it. Our lifting costs are really low because we use our natural gas. Plus, the field itself doesn't produce a lot of water, so we don't have large water infrastructure we have to build or disposal costs that we have. So that really helps, but it keeps our operating expenses really low, which leads us to having really good netback. So how much we make per barrel that we pull out of the ground.
You can see we're in the upper end of some of the best operators around, and there is a wide spectrum of that as far as how much they make per barrel of oil coming out of the ground, which also helps when oil prices are low, by the way, right? G&A has been coming down nicely year-over-year, and yearly net revenue has been coming up. A little bit about us, myself, I've got over 36, 37 years now in oil and gas, everything from land acquisitions to lots of operations experience, finance, and just generally running oil and gas companies. Gary, you want to just talk about yourself?
Sure. Yeah. So I have about 22 years in the energy business. I spent some time at Occidental Petroleum before I was here as a director of technical accounting. I have an MBA and a CPA.
My experience has been in public companies, both in the U.S. and Canada.
Thanks, Gary. Dan Simpson, our Director of Engineering, brings over 30 years of oil and gas engineering experience all around the world, frankly. Then Allan Hemeon, our Senior Geologist, over 15 years of experience in oil and gas and lots of years with us in this field. Evan Templeton, on our board of directors side of things, I like to say that I think we tick all the boxes. We have a well-rounded board. Evan Templeton, our Chairman, lots of experience in the oil and gas space on the credit side of things. For instance, he was a managing director of the Leverage Credit Trading Groups at Jefferies. Doug Urch, CFO of numerous oil and gas companies over his career, who is Chair of our Audit Committee. David Neuhauser.
He runs Livermore Partners, which owns about 17% of the company. So he's a large shareholder in the company and ticks the boxes on the corporate side of things for capital markets. And then Leslie O'Connor, our director, that's an engineering background. She ran the Denver offices for Sproule and MHA Petroleum Consultants that were engineering oil and gas consultants. So she has a great experience there. That kind of brings us to the summary. KGEI on the Nasdaq, KEI on the TSX, where we're trading. We've got cash flow that's been increasing. We're a good, efficient operator. We are, I mentioned earlier, added to the Russell 2000 last year. We were buying back shares, paying down debt. We keep our debt-to-EBITDA ratio. We'd like to keep it right around one or below.
Right now it's a little above, but by the end of the first quarter, we expect that to be well below. And we would generally drill based on cash flow and then using our line of credit to adjust working capital. So we think we have a great project. Pretty simple story, I think. And that's the summary. Thank you for all listening.
Thanks so much, Wolf. Thanks, Gary. As a reminder, we have about 10 minutes remaining. I see some questions already in the queue. If you do have questions, press that Q&A button at the bottom of your screen, type in the question, and we'll get to as many time permitting. There are a series of questions. There's some similarity between them, a lot about recent well results.
But I want to start with the first one, which is asking about, and it ties into a lot of your comments, which is the question is about your proved reserves, what you can say about your proved reserves growth this year.
Yeah. So we haven't put our forecast together yet, but what we're probably going to recommend to the board for the year is, a, I know that everyone wants to pay down debt, so we'll use the cash flow to pay down debt or pay it down to in the mid-30s or so, probably. And then also use that excess cash flow in the second quarter more aggressively to buy back some more shares, especially if shares are trading down here. So we do think we're undervalued.
But for the year in general, I think if it's in the $58-$60 range pricing-wise, I think it makes sense to keep production about flat. And so we'll probably do more of a maintenance type capital in order to drill a certain number of wells and maybe three or so in order to just keep production flat. That should allow quite a bit of excess cash flow to be generated, hopefully.
Is that tricky? Is that trickier for a company your size that is so focused on maintaining the balance sheet, knowing in a year where even more volatility potentially to WTI, given the geopolitical situation, given that there were plenty of macro forecasters saying we were going to be sub-50 WTI in Q1. We were talking about this before you started. We're at $60 now, but a lot of that's pushed to the right.
You got to make decisions about how many wells you want to drill. We're at $60 right now, great environment. You know what could be coming around the corner, but it keeps getting pushing to the right. How do you balance all that while trying to make sure you maintain a healthy balance sheet?
Well, I think that's the advantage that we have being the size we are. So we can do some things like what we're doing in first quarter is building numerous locations, numerous pads, right? So we can drill, do pad drilling from different areas of the field. So if oil prices pop up and we want to drill more than whatever we get approved for the year by our board, then we can quickly get a rig in there because the lead time is just getting the landowners to sign off, getting the location built.
And then if it's bad weather or something, you want to build locations when weather is good, right? So being proactive and picking numerous locations and spending a little bit of CapEx in that fashion really works. And then we can just turn on a dime. So what I was saying last year too, if oil prices suddenly were at $45, we just wouldn't have completed the wells or wouldn't have drilled the last couple of wells, right?
So you can drill and just wait if you need it, even if that.
Yeah, exactly. If it happens right in the middle of your operations per se, right? I mean, we did that a couple of years ago. We dropped one well of our drilling program, right? Because it was the prudent thing to do at the time. So yeah, that's the advantage that we have.
We don't have any long-term contracts, right? So we don't have to keep drilling.
But the other piece to this is obviously, and you looked at the stock chart. Part of it was oil prices, part of it was last March. There was a significant bump to your proved reserves, and your stock reflected that. Maybe as the year went on, it was not given quite the advantage. But part of your drilling program will grow your proved reserves, which certainly affects the valuation. And you talked about a number of areas where there's potential upside too if you chose to drill there, Sycamore being one you mentioned.
Correct. Yeah. So in 2024, we drilled a number of proved and probable, or a number of probable and possible locations, right? So that really bumped our proved reserves. This year, we focused more on the proved areas.
You'll see more of a move from your PUDs into your proved developed producing category and less firm increase on a proved category, most likely.
Got it. The question is about the differences between the different results from the Barnes and Velin wells, if you can sort of. And I know you've talked about this and it was in your press release. If you can just sort of give the general idea of why the Velin wells were so different from the Barnes.
We're still working on that as far as giving an exact reason for it and trying to figure that out. I mean, the wells were still improving even a few days before I made the last press release. As we had tubing in there, we're getting more fluid off the formation. Maybe those will keep cleaning up over time.
It's hard to say, or if they'll just stabilize here. They just acted differently. So we saw a little different results on the geology when we were drilling them that normally isn't a big deal, but that's the only thing we see differently in the faulting, and we're right next to a really large fault, so maybe that affected the geology. We're doing some more studies on that in order to figure out why, but we really think it's a localized event around there. We drilled 45 wells out here, and the one thing that a lot of people forget is everyone says shale, so it's homogeneous. It's going to be the same everywhere. Well, you can have pockets where things are a little different. Likewise, we had pockets where we had wells that were drastically exceeded expectations, so when you average things out, that's what happens.
Sometimes you have some that just don't end up being quite as good. The Barnes wells are performing really well, right? They're even better than the Lovina wells that we put out there that had good IRRs. Yeah, it's a numbers game, unfortunately, in shale gas. When you're small, everyone's looking at a single well, right? When the big guys drill, when they have wells that are a little less, they've got the other wells that are a little bit higher and it all averages out. That's the disadvantage of being our size that everyone's always looking at your last well and assuming that, oh, if that one's not good, then the rest might not be good. I think that's what the difference is where you can. The Barnes wells were really good wells.
Yeah.
And then in terms of, we know that the headline number around Alicia Renee were so high. But a lot of that was the much higher gas content.
Correct.
You've talked about some of these higher oil content wells having better netbacks, lower decline rates, helps the IRR. Can you talk a little bit about that, how people should think about that, not just focus on a headline number?
Yeah. This business, I mean, remember in the heart of when shale gas was first started, people were putting out instantaneous IPs, instantaneous initial production rates. Let me qualify that or clarify that for nomenclature, right? And it's meaningless, right? I can put out a rate that where I can open up the well for 10 hours or 24 hours and suddenly get a really high headline number. So it's really hard when you look at these wells.
One of the things we've learned is to slow down the flow back on them too. So everything that you just pushed out there, all the prop and everything else, you want that to stay in place. You don't want to flow it all back. And if you just open up the wells, that's what happens. So in our case, what we have seen is the wells that have the lower gas oil ratios that produce less gas per barrel of oil do have lower decline rates. And that's what we're counting on the Lovina wells, and that's what exactly has been happening. So that you can get to the same end result, but your curve isn't doing this, your curve is doing this. And so the ultimate EUR is about the same from those wells' estimated oil recovery, by the way.
Yeah, right.
So EUR, I should say.
So anyway, so that's the difference that we found. And Alicia Renee wells are really good. They just make more gas. And like you said, have a higher headline number. Lovina had a lower headline number where some people were actually disappointed. And our modeling showed that these are actually really good wells. And that's what we tried to put out with that press release as well. And then Barnes well should be even better.
Got it. So I'm going to ask you the impossible question that we were joking about before we started, which is you threw a lot of data out here, including the really high netbacks, the higher oil content than you have a lot of peers. But we show the comp table in a lot of the reports we put out.
Despite the higher net backs, despite the higher oil content, on an EV to proved barrel, you seem to lag a lot of what would be even grouped in the small cap peers. What's your take on that? I know it's an impossible question.
It is. It's hard to say. I mean, I think we and you're talking about where our stock price is, right? So I think we're really undervalued. I think there's a number of things that happened last year that people were at or the Russell 2000 inclusion had a lot of stock buying that happened in advance of that, right? Well, earlier than I thought would have ever happened, but they had to buy 3 million shares out of the market. And that really drove the stock price up, and maybe it drove it up a little prematurely over where it should have been.
It kind of came down on the backside of that, and then we had oil prices going down. That's kind of the combination. Sometimes things when they move up, I was shocked at how fast it moved up at that point in time going into it. I mean, it was vertical where I was expecting it to kind of step up, right, for a healthy increase. It just kept going up quickly. Usually when things go up quickly, sometimes they have an overcorrection on the downside. Then with the oil prices dropping, I think that's kind of a combination that was tough. It makes it a bargain for people to look in from my point of view at this point in time. I think we run our company in a good fashion. I think we have great asset, good company.
And we run comps in a good order and run everything in a good fashion.
So anything and speaking to that, any thoughts on it sounded like you said maybe reduced debt a little bit this year. Any thoughts on target net leverage where you think things might be?
I think we'll keep it below one. I'm comfortable with that. So yeah, let's put it this way. We would not have been above one if we'd completed, let's say if we drilled and completed those wells three or four weeks earlier.
So that's right. That's right. We are just about at a half an hour. We covered a lot of ground. Anything we weren't able to touch on or any closing comments you want to provide?
No, not really. I think, like I said, it's a pretty straightforward story in general. I think we're doing well. We're performing well.
I think people understanding that shale isn't homogeneous. And sometimes you have wells that are better. Sometimes you have wells that are worse. People can understand that. I think the Barnes wells point to the clarity on that personally. But some people maybe didn't like that and thought we would have those kind of wells from now on, which I disagree with. So dig in a little bit is what I would tell people. Take a look, and I think you'll like what you see.
Excellent. Wolf Regener, Gary Johnson from Kolibri Global Energy. Gentlemen, thanks so much for being here today. Hope everybody found this as informative as I did and hope everyone finds the rest of the conference useful as we wind down on day two of Sidoti's Micro Cap Conference. Thanks, guys. Thanks so much for being here.
Thank you.
Appreciate it. Thanks.