Kolibri Global Energy Inc. (KEI) Earnings Call Transcript
August 13, 2026
Earnings Call Speaker Segments
Good day, and welcome to the Kolibri Global Energy's Second Quarter 2026 Financials Conference Call. [Operator Instructions] Please note this event is being recorded. I advise participants that this conference call is being recorded today, August 13, 2026. This call will be available on the company's website at www.kolibrienergy.com. Here is a disclaimer. This call may include forward-looking statements -- forward-looking information regarding Kolibri's strategic plans, anticipated production, capital expenditures, exit rates, cash flows, reserves and other estimates and forecasts. Forward-looking information is subject to risks and uncertainties, and actual results will vary from the forward-looking statements. This call may include future-oriented financial information and financial outlook information, which Kolibri discloses in order to provide readers with a more complete perspective on Kolibri's potential future operations, and such information may not be appropriate for other purposes. For a description of the assumptions on which such forward-looking information is based on the applicable risks and uncertainties and Kolibri's policy for updating such statements, we direct you to Kolibri's most recent annual information form and management discussion and analysis for the period under discussion as well as Kolibri's most recent corporate presentation, all of which are available on Kolibri's website. Listeners should not place undue reliance on forward-looking information. Kolibri undertakes no obligation to update any forward-looking future-oriented financial or financial outlook information other than the required by applicable law. I would now like to turn the call over to Mr. Wolf Regener, the President and CEO of Kolibri Energy, Inc. Please go ahead, sir.
Thank you, and thank you, everyone, for joining us today. With me on today's call is also Gary Johnson, our Chief Financial Officer. So as hopefully, everyone has seen, we released our second quarter 2026 results this morning. And if you looked at them, I hope you share our excitement about the results. To say we are very pleased, it's an understatement. Our second quarter resulted in the company having its highest quarterly revenue, production and adjusted EBITDA in the history of the company. And this is in spite of having 3 of our wells shut in for 1/3 of the quarter. We also finished drilling the 3 Clifton Mack wells and are looking forward to beginning the completion operations on those shortly. I'm also very excited that we're starting to drill the Lovina 8-5-1HF well, which is our first test of the False Caney formation. I'm looking forward to testing this bench in our field. I'm excited about this because of all the data we have. We have a whole core that shows that the False Caney is highly oil saturated and it has excellent characteristics on logs from numerous wells in the field. I'm looking forward to the exciting times ahead for our company. With that, I'll now turn over the call to Gary to discuss our financial results. Go ahead, Gary.
Thanks, Wolf, and thanks, everyone, for joining the call. I'm going to go over a few highlights of the second quarter and the year-to-date results, then we take questions at the end of the call. All amounts are in U.S. dollars unless otherwise stated. I'll start by going over the second quarter. As you may have seen in our press release, our second quarter revenue was $22.5 million, which was our highest quarterly revenue in the company's history. Revenue increased by 109% from the prior year second quarter due to a 46% production increase and a 41% increase in average prices. Average production was up 46% to 4,690 BOE per day, compared to 3,220 BOE per day in the prior year quarter. That increase was due to the production from the wells that were drilled and completed during the second half of '25. Net income was $8.5 million and basic EPS was $0.24 per share, compared to $2.9 million and basic EPS of $0.08 per share in the prior year second quarter, which was an increase of almost 200%. The increase was due to higher revenue and an unrealized gain on commodity contracts, partially offset by higher operating expense and depletion expense due to the higher production. Adjusted EBITDA was $16.4 million compared to $7.7 million in the prior year quarter, which was an increase of 114% due to higher revenues, partially offset by higher OpEx and a realized loss on commodity contracts. Our netback from operations increased to $43.92 per BOE compared to $29.66 per BOE in the prior year quarter, which was an increase of 48%. This was due to higher average prices for the quarter, which were partially offset by higher operating expenses. Production and operating expense averaged $8.90 per BOE for the quarter, compared to $7.15 per BOE in the prior quarter, which was an increase of 24%. This increase was due to workover costs for a non-operated well, which added $0.59 per BOE and also temporarily higher water hauling costs compared to '25. So moving on to the year-to-date June results. Net revenue increased by 55% to $42.1 million compared to $27.2 million due to a 29% increase in production and a 19% increase in average prices. Average production for year-to-date June was up 29% to 4,688 BOE per day, compared to 3,646 BOE per day in the prior year period. And this increase was again due to production from the wells that were drilled during the last half of '25. Net income was $12.5 million and basic EPS was $0.35 per share compared to $8.6 million and basic EPS of $0.24 per share in the prior year period. The increase was due to higher revenue, partially offset by higher operating expense and depletion expense due to the higher production, higher interest expense and a realized loss on our commodity contracts in '26. Adjusted EBITDA was $31.3 million, compared to $20.5 million in the prior year period, an increase of 52% due to higher revenue, partially offset by higher operating expenses and a realized loss on commodity contracts. Netback from operations increased by 21% to $41.18 per BOE compared to $34.05 per BOE in the prior year period. This was due to higher average prices, partially offset by higher operating expenses. I also wanted to add that our credit facility was redetermined in the second quarter, and our borrowing base was increased by 15% from $65 million to $75 million. The continued increase in our borrowing base gives us more flexibility in managing our working capital going forward and also demonstrates the growing value of our property. So as you can see, last year's drilling program led to significant increases in revenue and cash flow across both the second quarter and the first half of the year. We anticipate the 4 new wells in our 2026 drilling program will add on to this growth, primarily in the fourth quarter when the wells are expected to be contributing a full quarter of production. And with that, I'll hand it back to Wolf.
Thanks, Gary. As Gary laid out, we had a great quarter with us hitting our highest ever quarterly revenue, production and adjusted EBITDA. And we're looking forward to more growth from the 4 new wells coming online. In addition, as I said in the beginning of the call, also really looking to the False Caney test. Having a successful False Caney well can open up the door to many more locations, reserves and thus value creation for all shareholders. And that is what I believe we are all here to do. This concludes the formal part of our presentation, and we'd be happy to answer any questions you may now have.
[Operator Instructions] And the first question will come from Steve Ferazani with Sidoti.
Obviously, great quarter. Wolf, the surprise to us was the strength in the 2Q production and the fact that they're really -- even if we factor in the volume adjustment by the gas purchaser, it's largely offset by the shut-in of the Alicia Renee wells. We exclude that, and there's virtually no sequential decline in production even though you added no new volume in the first half. And I'm just trying to figure out how that happens?
Wells did well. But yes, no, the wells are performing well. And when we bring these wells on, they flow for a while and then we put them on lift. And so we got a little boost again when we put them on lift, they had a little decline and then came back up again on that. And now they'll start the normal decline after that as well. So we're not going to stay flatline, unfortunately, until we fill these new wells on, which will go back up again. So that's [indiscernible] what's going on.
But when I think about that, were you -- those -- the 4Q wells, was it the Barnes [indiscernible], were you still optimizing those wells within Q1? Is that part of the factor here?
Yes. Well, it's more along the lines of what I mentioned as far as bringing the gas compression into the gas lift that helps it out again, right? So you have some decline in what's happening and then you can reverse some of that when you bring that on...
Got it. Gary, the gas purchaser volume adjustment, what quarter was that from? I'm just trying to figure out how it factored into your gas and NGL realized price?
It's related to several periods in the past, going back to '24 actually. So it's -- but just certain wells. But yes, it goes back quite a few months, quite a few years, actually.
Got it. Got it. You provided the updated guidance late June. Were there any new factors that weren't included in that guide, so we know we had the volume adjustment. I'm assuming late June, you knew that. You knew the shut-in of the Alicia Renee wells. I'm sure you had a reasonable sense of the timing of the 3 wells you're completing now. Any factors we should be thinking about that were not in that guide?
No, it will just depend on how these wells do -- that they're coming on the 4 wells. That's really the biggest factor on the...
But that's really what puts you...
On the guidance test, yes, because it's a lot of production coming on at once, right? And I mean, while our production has been growing nicely, right, close to 5,000 BOE. And -- but still bringing on 4 wells at a time that have high IPs really moves the needle a lot one way or another for a forecast. So that's our biggest variable, I'll say.
That's what would put you to the higher end. Because right now, you'd be -- I mean, to hit the low end of guidance, second half would be flat to first half. So it's reasonable to start thinking probably the low end is less low risk?
I don't want to overpromise anything, so I'm guessing...
Yes, I understand...
Our guidance is what we have...
I'm trying to guess just anyway.
Sorry, I'm not going to speculate. No offense.
But bigger picture, 3Q is -- based on the guide, 3Q is like is it going to be your low production quarter, 4Q is expected to be the high production quarter for the year?
Correct. You're absolutely right.
Okay. And then is the Lovina well in general, so it's a 2-mile well. You haven't done -- 2-mile lateral, you haven't done that before. How much of that is because it's in the False Caney or how much of it is the geographical location in the field, what's allowing you to try the 2-mile lateral for the first time?
Even on these 1.5 mile laterals, some of them are a little bit longer because they're sometimes coming into a section back a bit. So some of these not 1.5s, they are actually a little bit longer. But really -- I mean, it's a quiet area. We've had no -- we've been able to steer still at the end of our laterals. That was the hardest part for us in the beginning when we just had 1 mile laterals because we do have quite a bit of dip here. We've made this because that we don't have quite as much dip here. It's in the quiet area of the field where we don't see a whole lot of faulting. We have good control around it. So we feel comfortable that we can push it to the 2 miles out here on this well.
Got it. It's an exciting time. What would make you -- what are the factors in deciding whether you'll complete it or not or we don't know?
I would imagine -- unless we have a horrible drilling issue, we say we'll be completing that.
Which would then and that's the plan...
I can't imagine any scenario where we wouldn't.
And would you be using -- the timing-wise, would you be using the same spread?
It's probably -- I don't know if it's going to be the same or not. It will be a matter of timing, who's available for the right price too, right? So it is timing as well. So as soon as we're done drilling, we'd like to get the completion crew in as quickly as possible, much like we're doing on the Clifton Mack wells here.
Got it. Last one for me, just on the update on your production and operating costs. The water hauling, do you expect that to continue through this year? The workover is isolated to this quarter, fair?
Yes, the workover is definitely isolated to the quarter...
It was actually the first half because it was in the first quarter as well. The workover from our non-op was both quarters, but, yes, it should stop now. But the water hauling...
I think it should [indiscernible] how much we spent on 1 well.
Yes, we were [indiscernible].
And the water hauling, Gary, do you think that -- does that temper here? Or is it around this level for the year?
I mean, it's definitely going down throughout the quarter -- I mean, throughout the year so far. But I mean, it might be -- it's probably going to be higher than last year a little bit, but not much, but definitely going to taper down.
Got it. And then just generally on cost pressures, are you seeing them around your field?
We've had some increases. I mean some of our chemical costs have come up and up. And so we're putting actually some physical things in to try to knock those chemical costs down again. So we're in early stages of that. We think we're making some progress on that. But yes, I mean, there's been some cost escalation, but nothing too bad.
The next question will come from Nicholas Pope with ROTH Capital.
I got a couple of quick questions here on the operations front. Curious, with that Lavina well, first test here in the False Caney, you said you had that whole core look oil saturated. Curious what -- I guess, what's remaining from a risk standpoint as you kind of look at that well and how you all are expecting to communicate with the Street the kind of results of that well or maybe what you view as kind of successful relative to kind of what we're seeing in kind of the core Caney wells that you're already drilling, maybe comparing it with that.
Yes. Yes. So on a prospective basis, it's -- the zone is a little thinner. You can see that on our presentation, too, with how we -- it's more cartoonish than it is relative to one another. So it's a little thinner than the Caney itself. But if you look at how much acreage we have in our proved reserves for our Caney itself, it's like 11,500 acres net to us. And the Caney, we think has prospective over about 9,900 acres. So it's not as thick, and we have a lot of reserves in the Caney, right? We have 40 million barrels proved in the Caney itself. So even if the False Caney is thinner, even if you want to cut it in half, we're looking at something comparable, but we're hoping to be able to get a lot of reserves if we can make this work and it's repeatable. So really, what we're looking for is having a good well that's steered in this interval. We'll get the cuttings and get the analysis as we're drilling it as well. So we have a feel for what the rock looks like. Not anticipating any big surprises on that front. And then it will come down to just what the flow rates are from it and then what ultimately are the decline rates. But we've liked that core for a long time because it's a little thinner. We think the 2-mile laterals really make the economics work really well. And our steering has gotten better and better with the newer tools over the last 5, 6 years even. So we have high hopes that we're going to keep it where we want it, but our geology is going to be good, and it should be with the control we have and that we'll make a good well. And then there'll be what the flow rates are and what the 30-day rate is and actually declines thereafter. So it's hopefully going to be pretty -- I'm hoping it's very definitive right off the bat.
And how are you expecting these wells like their initial rates to compare to the -- for the Caney itself? Or is it too early? I'm hoping...
It's really too early. I mean I'm hoping we're making at least what the Caney wells are. It might have higher IPs maybe, but the perms look a little better, but we'll see. Let's let the production speak for itself when we do it. So I don't want to lead anyone too much one way or another on this.
Got it. Appreciate that. And then looking at these Alicia Renee wells that are shut in. Curious if there's any concern about performance once those come back online when the Clifton Mack wells are done? Or it's pretty straightforward to...
No, not at all. Yes. So it's just the way we had to redesign the programs, we had to drill them closer into where those were just to get around some of the faults that we found when we drilled that first one. And so it's -- that's the reason that they shut in. It's just we're drilling really close to where those other wellbores were, but it's the very toe end of those wellbores that are hitting the heel of the Clifton Mack wells. So even if we crack into it a little bit, it's just at the very heel of it and shouldn't affect the Clifton Mack much or the Alicia Renee much. And our wells in general, we actually get a bunch of flush production after these wells have been shut in for a while because they don't produce a whole lot of water. That's just the water that we've injected or it slowly comes back over time. So I'm anticipating some flush production out of the Alicia Renee when they come back on.
[Operator Instructions] Our next question will come from Richard Dearnley with Longport Partners.
The Clifton Mack wells with the casing problem was because one of the things was too much pressure. How much more pressure did they have than what you were expecting or versus the standard average Caney well?
Yes. And let me say it's not so much a casing issue. It's just that we had to use extra casing strings in these wells. So we had a lower pressure interval that was up shallower that we've not had in other areas of the field just in this area. So we had to put an extra casing string across that to isolate that. And then there were some higher pressures down at the bottom. So before we drilled the lateral, we set another string right there before we drilled the lateral in order to hold everything back and keep everything isolated. That's kind of tough. It's always been kind of a tougher interval for us right at that transition from the Springer into the Caney formation. So really, that's the extra security that was there for these wells that we felt that we had to do in order to go forward. Yes, it showed us higher pressures. I don't have a quantifiable number on that. And so we'll just see what she does when we come back. Really, the only pressure we can really get is once we actually fracture stimulate and start getting fluid back out of the rock. So for that, it's -- we use higher mud weights here to drill it to keep everything in place. So that's the reason for the higher pressures that we mentioned.
Right. And what did they end up costing?
Well, we haven't specified it specifically, but they were more expensive than our normal wells.
Is that classified info?
No, just we haven't disclosed yet. So I can't -- whatever we didn't specifically put in the press release, so I can't say on the call either because otherwise, we have to do another press release to disseminate that information. I'm not trying to be difficult, but have to be careful about what we disseminate to everyone per the rules.
Right. Well, it would be useful to know that when you release the IP or EUR estimates, just the background. And...
Absolutely, I understand. But the good part is that -- the part is no matter what these wells cost, we're still guiding toward our normal Caney wells still being that same cost because in the rest of the field, we don't have to do these extra casing strings.
Right, right. And is the gas oil ratio heading north this quarter, is that a one-off or the base -- the average -- your base wells getting gasier?
No, it's -- so part of it is this adjustment that came in that dropped it down a bit lower as well. And you'll see we have a note in our -- I can't remember in the press release or the MD&A...
MD&A. Yes, it was 70% in May and June. So it kind of got skewed by that adjustment for the quarter. That's why it was really low. But yes, so we're tracking, set the max at 70% in the last few months.
Yes. And basically, the 74% that was in the first quarter was the new wells that came on had a higher percentage oil -- oil percent. And while the oil is tracking what the decline has been, we did start getting additional gas coming in. So they're actually on a BOE basis came up a little bit more than expected. Oil stayed kind of what we expected, but more gas came in, so that dropped that down a bit.
Okay. And you said that you expect the False Caney well to be oil saturated. Well, your base is very oil saturated already. Are you expecting higher oil saturation from the False Caney?
No, we won't know what the percentage is until we drill it. But all we're saying is that when you have whole core, our Caney was oil saturated as well. So it's just an indication that there is oil in the False Caney. And then what the rates are and what the percentage oil to gas is, we'll see when we fracture stimulate and when we produce them back.
And this will conclude our question-and-answer session. I would like to turn the conference back over to Mr. Wolf Regener for any closing remarks. Please go ahead, sir.
I just want to thank everyone for being supportive of the company and shareholders and also taking the time to listen to us today and ask questions, et cetera. Thank you, everyone. Have a great day.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
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