Back to Sidoti & Company's virtual investor conference. Still waiting for the room to fill in a little bit here. Before I turn it over, I am Stephen Michael Ferazani, Equity Analyst at Sidoti & Company. I'd like to remind everyone, we do this before every presentation, just as a reminder. If you do have questions following the presentation, time permitting, we will try to take some questions. Press that Q&A button at the bottom of your screen, type it in, and we'll get to as many as possible. Having said that, it looks like the room has pretty much filled in, so I'm excited to welcome Kolibri Global Energy Inc., the ticker is KGEI. We're joined today by CEO Wolf E. Regener. With that, Wolf, let me turn it over to you.
Hi, thank you, everyone. Appreciate you coming and taking the time today. Here is our corporate presentation. You can find this on our website as well, or all the forward-looking information, the disclaimer, non-GAAP measures, et cetera. For those of you that don't know much about the company, I'll cover the basics as well. We're an oil and gas producer in Oklahoma. We're drilling shale wells in the Tishomingo Shale Oil Field. They're all horizontal wells. We drill down vertically, then go horizontal. We had been drilling for about a mile, and now we go to a mile and a half to two miles on some of these wells. We try to run our business in a financially stable fashion, keeping low debt. We've had really good cash flow growth. We're looking to continue that.
We have high netbacks production, so how much we make per barrel of oil that we pull out of the ground. Fully funded for a 2025 drilling program. Expect to do the same thing for 2026, even though we haven't announced anything yet what our plans are. Just using our existing cash flow and our existing line of credit. Speaking of that, we have a $65 million line of credit with Bank of Oklahoma, where we have about $34 million or so available to us right now. By the end of the year, we expect to be about in that same stage of having about $30 million outstanding. We've got what we consider a high-quality asset, Netherland, Sewell & Associates, Inc., a very reputable engineering firm, does our reservoir engineering. We have proved reserves of about 40 million barrels, proved probable of about 53 million barrels.
We have a large amount of our proved reserves that are still in the proved undeveloped category. Netherland, Sewell & Associates, Inc. has verified these reserves for us. These are numbers as of the end of last year, so it doesn't include the new drilling that we've done this year. At the end of last year, we had 22% of our reserves in the proved developed producing category of our proved, and then 78% was unproved, undeveloped. Last year, we improved our reserves by about 24% by drilling some wells that were in the probable and possible categories. Going to the company itself, we originally listed just on the TSX up in Canada under KEI. We have a NASDAQ listing. We're a foreign private issuer under KGEI. 35.5 million shares outstanding. We're trading around $40-ish. That gives us a U.S. market cap of about $193 million.
Again, debt at the end of the third quarter was about $27 million. That compares to Netherland, Sewell & Associates, Inc. at the end of last year's reserve report with the 40 million barrels proved of $500 million. Then our proved and probable reserves of close to $700 million. It is at a price deck that's a little bit higher than where we are right now. It's in the mid-70s. We're now in the mid-60s, but you can see that there's a big disconnect still on the valuation between everything. A little history here in 2020 through the COVID era and things like that. We had kind of a split board where half the board wanted to drill, half the board didn't. You can see what happens to a stock when you don't drill wells. The board changed out.
We also changed the name of the company to Kolibri Global Energy Inc. at the time. Started drilling wells again. You can see the results we've had on the stock price has come up nicely. Still have more to go, in my opinion, but also on the net income, on EBITDA, et cetera. I'll show you in a couple more slides. A little background here for this project itself. We're located about halfway between Oklahoma City and Dallas. We originally were drilling for what's called the Woodford Shale. The Woodford Shale, we were producing about 15% oil, and the balance was gas and natural gas liquids. Very gassy, obviously. Exxon started buying out everyone around us. You can see down here in the purple, they picked up about 280,000 acres, and we were the last holdout. We had about 12,500 acres.
We drilled and participated in about 40 wells across that acreage block. Eventually, we were able to negotiate Exxon up to $147 million. We held on to the rights of all those intervals that we had of the shallower Caney and upper Sycamore. The Woodford is down here, and the Caney and Sycamore is above it. We're the only ones that were able to hold on to that. The reason we did so was we had just drilled our first horizontal Caney well. Wasn't economic, but we felt like we could make economic wells out of the Caney, but it would take a while. Exxon didn't want to pay us what we thought it was worth at the time. We held on to it. That's what's now grown into reserves of 40 million barrels proved, 53 million barrels proved probable.
It really transformed us into an oil producer from a natural gas producer. Now, you know, our numbers are about 70% oil and the balance of gas and natural gas liquids. Our whole product stream is only about 16% natural gas now. For 2025, development of the field has been going on. We've been drilling wells. We drilled four mile and a half lateral Caney wells and drilled a well on the east side. I'll cover on the east side on a later slide, but that's an area that we didn't have anything in the reserve report. It's upside for us and where we're testing the Caney out there. In the third and fourth quarter here, we've brought on the Lobina wells that we drilled. The exciting part is that the Lobina wells were producing about 82% oil, versus our 70% average. It's came much higher.
The positive side of that is that it should lead to higher netbacks, even higher than what we have already from these wells. We're now testing the economics of the east side well, the Forguson. Like I said, I have another slide that we can go into that. We're in the process of drilling two more mile and a half lateral Caney wells called the Barnes 6-31 2H and the 3H. We'll be completing those wells along with the two previously drilled one mile lateral Caney wells, which are called the Velence. That'll be happening in the fourth quarter here. Forecast for the year, you can see our adjusted EBITDA has been growing nicely since we started drilling again. Everything is moving along the right way. We've got nice increases coming.
We'll probably be on a little bit on the lower side of our range, just to be upfront about everything. With our capital expenditures coming in, hopefully as expected, that'll still give us money extra. With that extra money, we've been buying back shares. We authorized a, or the board authorized a share buyback program last year. We're in the process of renewing that again. We bought back about just over 500,000 shares at an average price of about $520 something US. We'll look to continue to buy back shares. Production has been climbing nicely. This is on a quarter by quarter basis. The drop in second quarter was because we shut in some wells that are directly offsetting the Lobina wells in order to protect them during the fracture simulation. That caused that harder drop than just the natural declines that we were on.
You'll see that come back up again. The four Lobina wells at a combined rate over 2,000 barrels a day. You can see what kind of difference that will make, just adding that, including the additional wells coming back on, the old wells coming back on. The net operating income, same thing, has been coming up nicely. The drop again is caused by the stimulation, the shut-ins that we did during the stimulation. The red line shows the barrel of oil equivalent pricing that we get. Even though oil and gas prices have come down, you can see our net income is climbing up. We look to continue that increase here going forward. For the field itself, all the infrastructure is in place. The gathering system for the natural gas and natural gas liquids is less than a mile from all of our locations. Exxon has the entire system there.
We sold our portion of the system to them back when we sold them the Woodford. We now have the gas system that we can tie into that's close into all the wells that we're looking at, and that's all the approved locations. Our oil out here is priced at a WTI less than $1.85. That's been very consistent over the last five, six, seven years. There haven't been big differentials. Some of these basins have big differentials that come in, the differential between West Texas Intermediate and what they're getting. Ours has been very consistent at about $1.85 a barrel. Netherland, Sewell & Associates, Inc. has given us 52 approved locations, 31 probable locations, and 21 possible locations. Those are all mainly mile and a half and two mile laterals this year. Mentioned we grew the acreage from that $12,500 when we sold originally to 17,000 acres.
We have 41 Caney wells on production, including Lobina and the Forguson well. The nice part is our acreage is all held by production, or almost all, I should say. That means we can have the option of drilling where we want to drill, when we want to drill, and we don't have to worry about losing leases in most of these areas. In addition to the Caney, we have some upside from the east side, which is where that Forguson well is. There are also two other intervals that are in between the Caney and the Woodford that we have the rights to, which is the T zone that we drilled a couple wells into. One of those interfered with the Caney itself. What we decided was we'll complete and drill and produce the Caney.
When those decline down to a certain level, we can come in and drill some more T zone wells. If it interferes, it doesn't matter as much. Because in some areas it will, in some areas it won't. There is also the upper Sycamore. Some other operators have drilled some nice upper Sycamore wells in the area. We do have the Sycamore across our acreage. We're looking into where it makes the most sense in order to test that in the future. That's the other upside that we have. The east side that I mentioned, we have 3,000 net acres on the east side of our acreage. All of our acreage is contiguous, by the way, but it's never been tested for the Caney itself. The 3,000 net acres have been listed as a contingent resource by Netherland, Sewell & Associates, Inc.
The Caney, because we drilled those Woodford wells through it, so we know what it looks like. That has very similar characteristics and thicknesses as the heart of our play, except for it's shallower. It has a little less energy, so it's going to take a little longer to get our fracture stimulation fluid back. Even before we drilled, I was sure that we were going to make an oil and gas well. I've been saying that it's just a matter of what the economics are of it. How much is it going to produce? What kind of oil and gas pricing do we need in order to make economic wells out here? Our last announcement was that we'd only recovered about 2.6% of our fracture stimulation fluid from that well and it's making about 160 barrels of oil equivalent a day.
Generally, our wells, we know that they've peaked out when we hit between 7% and 10% recovery. We had a ways to go to find out if this is peak rate or if it'll keep cleaning up, which we hope, and to go a little higher. We'll see what kind of decline it has in order to figure out what the economics are. Again, that's upside for the field. If we can make that work, then that's fantastic. That gives us a bunch more locations out here. We are the operator of it. We have a 46% working interest and a large integrated oil company also had interest in this area, so they have the balance of this. Over the years, we've gotten better and better at drilling these wells. For one mile lateral wells, in 2016 and 2017, it was taking about 30 days to drill these wells.
By the end of 2024, we had it down to 12 days. This was drilling down to between 8,500 and 11,000 feet and then going horizontal by a mile. Those last four mile laterals were completed for an average cost of $5.5 million, where in 2023, the forecast was for $7.2 million. The first three mile and a half laterals that we drilled were drilled in 14 days and only took us two days extra. The Lobina wells were drilled in an average of 10.5 days, so we got even better at that. The Barnes wells that we're drilling now have a budgeted cost of about $7.2 million. Really, including the cost increases from tubulars and steel that have gone up recently, we're now drilling mile and a half lateral wells for what it was in 2023 for one mile laterals.
If you think about it, for the same price, we're getting 50% more access to the reservoir now to make better and better wells. Rates of return, these are at a little lower well cost at $6.5 million, which is where we were last year before some of the price increases that we had. It shows Netherland, Sewell & Associates, Inc.'s estimate of what these wells would do in a gassier area and a less gassier area in the heart of our field and what kind of internal rates of return we would get assuming they produce along those rates of what they estimated at different constant held oil prices.
You can see even in a $60, $65 oil price, it's somewhere between a 50% to over 100% rate of return depending on the well location that we pick, even at a $60-ish oil price, assuming they produce along those rates. That's one of the reasons that we continue to drill wells, even in the lower oil price environment. Excuse me for a sec. Some more on our efficiencies. Our operating expense per barrel of oil equivalent, this is taken from 2024 numbers from annual reports for other public companies that we consider our peers. You can see we're at the lower end on operating expense of how much it takes to get a barrel of oil out of the ground. The ones around us are mainly natural gas producers. With natural gas, it flows out of the ground naturally and you don't have to have a lift mechanism.
That's why it looks, that's why these other ones are around us, but we're very efficient in how we get the oil out of the ground. That leads to very high netbacks as well. Our SEC calculated netbacks for us for last year, you can see that we're in the very upper end along with some other good operators that have low operating costs and have high netbacks. G&A has been coming down nicely over the years. Excuse me. Our yearly net revenue has been climbing along with everything else that we've had. A little background myself, over 36 years of oil and gas experience, lots of operations experience, land acquisition experience, finance, and generally just running oil and gas companies over the years. Gary W. Johnson, our CFO, brings over 34 years of accounting and finance experience, and 22 of that is in the oil and gas business.
For instance, one of his jobs, he was Director of Technical Accounting at Occidental Petroleum. Dan Simpson, our Director of Engineering, has over 30 years of petroleum engineering experience all across the world. Alan Hemmy, our Senior Geologist, has over 15 years of oil and gas experience now. Board of Directors, we have Evan Templeton, who is our Chairman. He has lots of analyst experience in the oil and gas space, in the high-yield leveraged loan markets. He was Managing Director, for instance, in the leverage credit trading group at Jefferies. He's been a great addition to our board here over the last few years, and he's our Chairman. Doug Erch, who's head of the Audit Committee for us, he's been CFO of multiple different oil and gas companies over the years.
David Neuhauser runs Livermore Partners, a large shareholder of the company, and brings lots of capital markets experience to the table as well. Leslie O'Connor brings lots of reservoir engineering experience. She's retired now, but she used to run MHA Petroleum Consultants and also Strul's Denver office, which are both reputable reservoir engineering firms. What I'd like to say is we, I think, with our board and management, we kind of tick all the boxes, cover all the bases, so to speak, for what a company needs. That's really the summary. Traded KEI in the TSX, KGEI on the NASDAQ. We have low debt. We've got a lot of drilling inventory left. We've got shareholder return policy for buying back shares. Looking to keep growing the company. Have some catalysts coming up with the new wells. There are four more wells coming on here in the fourth quarter.
Just looking to continue the drilling program and looking forward to further increasing approved reserves. We are looking for other accretive acquisitions if we can find some. We've kicked the tires on a lot over the years. Haven't found anything that really makes sense yet. That doesn't mean we keep looking. We're looking to, yeah, generate more cash flow and then return more money to the shareholders as well.
Thanks so much, Wolf. I think that's an informative overview of Kolibri Global Energy Inc. We are already getting a few questions in. Remind everyone, we have about 10 minutes remaining. If you do have questions, press that Q&A button and type them in and add them to the queue. We should have some time to dig into a few topics. The first one I want to take, and it's probably the one you least want to talk about, is, and this is coming from one of the people watching, and I'll sort of paraphrase it. Obviously, oil price outlooks by some of the leading forecasters are lower for 2026, in some cases below $50. When do you start thinking about budgeting, drilling, and completion programs for next year? How will you use oil price outlooks at that time?
We see what the oil price outlook is. We generally do that closer to the end of the year in general. What we like to do from the field aspect of things, we prepare everything so we can move in routes quickly. We like to be prepared on multiple fronts and multiple locations so we can adjust things quickly. That's the advantage of being a smaller company. We decide where we think oil prices are at that point in time when we put our forecast together. If we have drastic changes in the oil prices, we just adjust.
You will mid-year if you want to. This year, you were pretty much in line. Timing was a little bit different. Next year, knowing the volatility in the world right now, your ability to add rigs or cut rigs is not going to be that hard.
Yeah, I mean, that's rig availability, et cetera, always comes into it.
That doesn't seem to be an issue right now.
No, it's not an issue right now. I'm just saying in general, right? Those are the challenges that are outside of the thing out of control. Right now, that's not an issue. The completion side of things isn't an issue either. We have the ability to adjust. Like I was saying to someone yesterday, it's like, they're like, what if oil, you know, dropped tomorrow to, you know, $45? I'm like, OK, then you know what? Maybe we hold off on completing these wells that we're drilling right now, right?
Right.
You have the ability to do that quickly. We're not tied to long-term contracts on anything, so we have the ability to adjust quickly. That's, like I said, the advantage of being a smaller company.
Correct. Speaking to that, the two, you're drilling two wells now. Where are you in that? Do you have any expectation on timing of production? You're going to drill two, but you're also completing two of the older mile laterals at the same time.
Correct. Yeah, so we're hoping, and obviously in the fourth quarter, early in the fourth quarter, we're looking to start fracture stimulating those. In my last press release, we announced that we were just running casing on the first of those two wells. You can imagine we're pretty far along on the second one as well. We're looking at completing those sometime in October and hopefully bringing those on in early November-ish.
OK. I'm assuming same thing, it's not hard to get fracking services right now. Timing may be tricky, but actually, yeah, you're right.
You can find services. It's just a matter of when they're coming off of a job or et cetera. It's weeks one way or another sometimes. That's about it.
We do have a question about your content or mix. Obviously, the Lobina wells were much more liquids rich than some of the previous wells. Sort of the reverse of Alicia Renee, which were very high initial production, but very gassy. Knowing what's in the ground, do you have any kind of thoughts on how mix will change over the next few years? Or is it really depends on what?
It depends on the location. Yeah, exactly. We knew the west side was going to be gassy. It was actually Alicia Renee came in a little gassier, had a little bit more energy, so to speak, up front than we had anticipated. We knew those were going to be a little on the gassier side. We also had a feeling that these were going to be a little on the oiler side. The 82% or so that were oil on this one surprised us as well. The bright side of that is it should lead to higher netbacks and hopefully also lower declines because the gas doesn't bleed off. We'll see how those wells perform. I'm happy with what I've seen so far out of them.
Any thoughts on when you may have a better idea about Forguson and when you could think about, is the east side, are you going to drill more? It's way too early, I know, but any idea when you'll get a sense?
No, it's going to see how it is. For us, it's easier to predict what a well is doing when it looks like another well. We're on the east side here. We're in a different animal just because it's a little shallower, right? We haven't drilled anything out there that's that shallow. We really need time to, A, get the frac fluid off, which is coming off still. Once the frac fluid is off, we have to see what kind of declines it has. It'll be a few months until it starts fading into a pattern of something else. We can say, OK, yeah, we feel comfortable about that, and that's probably what it's going to do. Until we see something like that, hopefully it just flatlines for a long time and continues to clean up the line.
Absolutely.
I'm waiting as anxiously as I'm sure some of our shareholders are.
Some questions around M&A activity in the space. You've talked about being an acquirer. Obviously, there's not a lot of publicly traded small cap E&Ps left, certainly not liquids rich ones like yourself. How are you seeing M&A activity playing out in what potentially is a slightly lower priced environment?
Yeah, that's hard to predict, right? That's hard to predict. I think, yeah, some people have taken a window that were tied up for a long time in order to sell, and they're willing to sell it at the prices we're at now. You see other guys that are saying, no, this is a temporary blip and they're waiting for higher prices. You've had some interesting comments on some of the Canadian operators too, where people are like, why did you put this thing into play at lower prices? From our point of view, for the company, I'll say as a whole, one of my board members likes to say, we're in the stage of we either go or grow. We either have to find something that's accretive or at some point in time, someone's going to come along and buy us.
For the right price, we're always for sale as well ourselves. If we can pick up things that are accretive, I think that makes sense as well.
Given that the way you've been conservative on the balance sheet and drilling with cash flow, there's no rush one way or the other.
It has to be something that, for us to buy something, it has to be something that really fits.
Yeah.
That has to fit what it is. We've probably looked at easily 25 or maybe 30 deals over the last couple of years. We haven't seen anything that we liked that makes sense for the company. That's no different now. We're going to still keep looking and see if something is a good fit and something that's accretive for the shareholders. Then great, we'll see if we can do that.
Got it. You noted in 2Q you did have the impact from the shut-ins around the completions. Any thoughts in 4Q as you complete these four more wells based on where they're located? Thoughts on shut-in impact at this point? How would you be thinking about production impact?
There will be an impact whenever we're fracking wells now. We have an impact on some of the existing production for sure. All these areas are a little bit different. We've taken some steps to minimize some of that. What we did this time was less impactful than what happened to us the time before when we were near other wells.
I'm assuming the goal is to try, and it can't be perfect, but I'm assuming you, the locations you try to pick are near older wells. Is that a fair way to think about it?
Yes, absolutely. Absolutely.
OK.
It is advantageous now for us to drill four wells at a time, right?
Do them all.
That's why we didn't, that's frankly why the Velence wells weren't completed when they were drilled, because we had the impact of some other fracs. We said, OK, let's hold off. Let's drill a couple more wells in that area and then bring them all along.
Do them right, so you're not impacting twice. That makes a lot of sense.
Yeah.
You showed a couple of interesting slides regarding the strong netbacks, the lower costs. When you think about your evaluation to a peer group, given those higher netbacks, given the higher liquid content, given the operating efficiencies, how do you think about it?
Obviously, we should be trading it at a premium.
Yeah.
No, but I mean, seriously, we're doing better than a lot of operators out there, from my point of view, that are our size. We make more money per barrel on being rich. That also allows us to ride out the leaner times, right, when you're talking about lower oil prices. One of the things I'm saying is even if oil prices are down lower or dip down lower, I'm still able to sleep at night because our company is in really good shape. We're not over-leveraged, right? We make a lot per barrel that we pull out of the ground. In this business, it's a volatile business, right? It goes up and down. You have a lot of ups, and then you have some downs that happen. I've been doing this for a long time and never gone bankrupt in any company.
This one is way, way solid, way better than some of the other things I've been in my career.
Fair enough. We are just about out of time. Any closing comments before we wrap it up, Wolf?
No, not really. We're just going to keep doing our business, go forward doing the best that we can through this business. I appreciate everyone's time looking at this, and feel free to ask questions whenever you all have them. I appreciate you guys, Sidoti & Company, setting all this up.
Thanks so much, Wolf E. Regener, CEO of Kolibri Global Energy Inc. If you do have further questions for Wolf, we didn't get to them during this 30 minutes. Certainly, you can reach out directly to me at Sidoti & Company or to Sidoti & Company in general or directly to Wolf at Kolibri Global Energy Inc. We'll certainly get as many questions as we can, if not all, answered for you. Wolf, thanks so much for being here today. Hopefully, everyone enjoys the remainder of the conference.
Appreciate it. Thanks, everybody.