Prepared remarks
Good day, and welcome to 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. This call may include forward-looking statements and 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, 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 or future-oriented financial information or financial outlook information other than that 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. As hopefully everyone has seen, we released our second quarter 2026 results this morning. If you looked at them, I hope you share our excitement about the results. To say we are very pleased is 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 three of our wells shut in for one-third of the quarter. We also finished drilling the three 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 the call over 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'll 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 2025. 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 2025. 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. This increase was again due to production from the wells that were drilled during the last half of 2025. 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 2026. 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 four 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. We're looking forward to more growth from the four new wells coming online. In addition, as I said at the beginning of the call, we're 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. 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.
Questions and answers
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 second-quarter production and the fact that — 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. If we exclude that, there's virtually no sequential decline in production even though you added no new volume in the first half. I'm just trying to figure out how that happens?
Wells did well. The wells are performing well. When we bring these wells on, they flow for a while and then we put them on lift. 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. Now they'll start the normal decline after that as well. So we're not going to stay flatline until we bring the new wells on, which will push production back up again. So that's essentially what's going on.
But when I think about that, were you — those 4Q wells, was it the Barnes wells, were you still optimizing those wells within Q1? Is that part of the factor here?
Yes. 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. You have some decline and then you can reverse some of that when you bring gas lift 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 2024 actually. So it's certain wells and it goes back quite a few months, even a few years in some cases.
Got it. You provided the updated guidance late June. Were there any new factors that weren't included in that guide? I know we had the volume adjustment — I'm assuming late June you knew that. You knew the shut-in of the Alicia Renee wells. You likely had a reasonable sense of the timing of the three 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 — the four wells. That's really the biggest factor.
But that's really what puts you...
On the guidance test, yes, because it's a lot of production coming on at once. While our production has been growing nicely, close to 5,000 BOE, bringing on four 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.
That's what would put you to the higher end. Because right now, to hit the low end of guidance, second half would be flat to first half. So it's reasonable to start thinking the low end is less low risk?
I don't want to overpromise anything, so I'm not going to speculate. Our guidance is what we have provided.
I understand. Bigger picture, is the third quarter, based on the guide, likely to be your low production quarter and the fourth quarter the high production quarter for the year?
Correct. You're absolutely right.
Okay. And then the Lovina well in general — it's a two-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 that's allowing you to try the two-mile lateral for the first time?
Even on our 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 1.5-mile laterals are actually a little bit longer. It's a quiet area. We've been able to steer well at the end of our laterals. That was the hardest part for us in the beginning when we just had one-mile laterals because we do have quite a bit of dip here. In this area we don't have quite as much dip; it's a quiet area of the field where we don't see a lot of faulting. We have good control around it. So we feel comfortable that we can push it to two miles on this well.
Got it. What would make you decide whether you'll complete it or not, or do you already know?
Unless we have a horrible drilling issue, we'll be completing that. I can't imagine any scenario where we wouldn't.
And timing-wise, would you be using the same spread?
It might not be the same. It will be a matter of timing and who's available for the right price. 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.
Got it. Last one: 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 in the first half because it was in the first quarter as well. The workover from our non-op was in both quarters, but yes, it should stop now. Regarding the water hauling...
I think it should depend on how much we spent on one well.
Yes, we were affected.
And the water hauling, Gary, do you think that tapers here? Or is it around this level for the year?
It's definitely going down throughout the year so far. It might be a bit higher than last year overall, but not by much. It will definitely taper down.
Got it. And then just generally on cost pressures, are you seeing them around your field?
We've had some increases. Some of our chemical costs have come up, so we're putting in some physical solutions to try to reduce those chemical costs. We're in the early stages of that and think we're making some progress. Yes, there has been some cost escalation, but nothing too bad.
Operator Instructions: The next question will come from Nicholas Pope with ROTH Capital.
I have a couple of quick questions on the operations front. Curious, with that Lovina well, first test here in the False Caney, you said you had a whole core that looked oil saturated. Curious what remains from a risk standpoint as you look at that well and how you are expecting to communicate to the Street the kind of results of that well, or maybe what you view as kind of successful relative to what we're seeing in the core Caney wells that you're already drilling, maybe comparing it with that.
On a prospective basis, the zone is a little thinner. You can see that on our presentation as well — it's more cartoonish than relative to one another. It's a little thinner than the Caney itself. But if you look at how much acreage we have in our proved reserves for the Caney itself, it's about 11,500 acres net to us, and the Caney prospective is about 9,900 acres. So it's not as thick, and we have a lot of reserves in the Caney — we have 40 million barrels proved in the Caney itself. So even if the False Caney is thinner, even if you cut it in half, we're looking at something comparable. We're hoping to be able to add a lot of reserves if we can make this work and if it's repeatable. Really, what we're looking for is having a good well that's steered in this interval. We'll get the cuttings and analysis as we're drilling it, so we have a feel for what the rock looks like. I'm not anticipating big surprises. Then it will come down to the flow rates and the decline rates. We've liked that core for a long time — it's thinner but the two-mile laterals make the economics work well. Our steering has improved over the last five to six years with newer tools, so we have high hopes we'll keep it where we want it. The geology should be good given the control we have, and we'll see what the flow rates and the 30-day rates and declines are thereafter. I'm hoping it will be very definitive right off the bat.
How are you expecting initial rates to compare to the Caney wells themselves? Or is it too early to say?
It's too early. I'm hoping we make at least what the Caney wells are. It might have higher IPs — the perms look a little better — but we'll see. Let's let the production speak for itself.
Appreciate that. And then looking at the Alicia Renee wells that are shut in, any concern about performance once those come back online when the Clifton Mack wells are done, or is it pretty straightforward?
No concern. We had to redesign programs and drill closer to where those were to avoid some faults we found when we drilled the first one. That's why they shut in. We're drilling really close, but it's mostly the toe end of those wellbores that are near the heel of the Clifton Mack wells. Even if we intersect a little, it will be at the very heel and shouldn't affect either set of wells much. In general, we often get some flush production after wells have been shut in for a while because they don't produce a lot of water; that's mostly injected water slowly coming 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 situation — was that because one of the zones was at higher pressure? How much more pressure did they have than what you were expecting or versus the standard average Caney well?
It's not so much a casing issue. We had to use extra casing strings in these wells. We encountered a lower pressure interval up shallower in this area that we haven't seen in other parts of the field, so we had to put an extra casing string across that to isolate it. Then there were some higher pressures down at the bottom, so before we drilled the lateral we set another string to hold everything back and keep it isolated. That transition from the Springer into the Caney formation has always been tougher in that spot. I don't have a quantifiable pressure number to give you. We'll really see pressures once we fracture stimulate and start getting fluid back out of the rock. We used higher mud weights to drill and keep everything in place, which is why we mentioned higher pressures.
Right. And what did those wells end up costing?
We haven't specified it specifically, but they were more expensive than our normal wells.
Is that classified information?
No, it's not classified. We just haven't disclosed the specific costs yet. We didn't put that detail in the press release, and I can't provide new material on the call without issuing another press release to disseminate it properly. I'm not trying to be difficult, just being careful about public disclosure rules.
Fair. It would be useful to know that when you release the IP or EUR estimates, just for background. And is the gas-to-oil ratio heading north this quarter — is that a one-off or are your base wells getting gasier?
Part of it is the adjustment that came in that lowered the ratio for the quarter. We have a note on that in the MD&A. The lower ratio showed up because of that adjustment.
Yes, in May and June it was around 70%, so the quarter got skewed by that adjustment.
In the first quarter the 74% was driven by new wells that had a higher oil percentage. While oil tracked as expected, we started getting additional gas coming in, so BOE came up a little more than expected. Oil stayed roughly as expected, but more gas lowered the oil percentage.
Okay. You said you expect the False Caney to be oil saturated. Your base is already very oil saturated. Are you expecting higher oil saturation from the False Caney?
We won't know the exact percentage until we drill. All we're saying is that the whole core indicates there is oil in the False Caney. Our Caney was oil saturated as well, so it's an indication of oil presence. The rates and percentage oil-to-gas will be revealed after fracture stimulation and production.
This concludes 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 our shareholders and for taking the time to listen to us today and ask questions. Thank you, everyone. Have a great day.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.