Good day and welcome to the Colibri Global Energy's second quarter 2026 financials conference call. All participants will be in a listen-only mode. Media may monitor this call in a listen-only mode. There are free to quote any member of the management but are asked to not quote remarks from any other participant without the participant's permission. If anyone has any trouble and needs assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then 1 on your touchtone phone. And to withdraw your question, please press star then 2. 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.colibrienergy.com. Here is a disclaimer. This call may include forward-looking statements, forward-looking information regarding Colibri's strategic plans, anticipated production, capital expenditures, exit rates, cash flows, reserves, and other estimates and forecasts. Forward-looking information is subject to risk 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 Colibri discloses in order to provide readers with a more complete perspective on Colibri's potential future operations and such information may not be appropriate for other purposes. For a description of the assumptions on which such forelooking information is based and the applicable risk and uncertainties and Colibri's policy for updating such statements, we direct you to Colibri's most recent annual information forum and management discussion and analysts for the period under discussion, as well as Colibri's most recent corporate presentation, all of which are available on Colibri's website. Listeners should not place undue reliance on forward-looking information. Colibri 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. Regener, the president and CEO of Colibri 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 of 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 is an understatement. Our second quarter resulted in the company having its highest quarterly revenue, reduction, 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 Lobina 8-5-1HF well, which is our first test of the Falls 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 volcano is highly oil saturated, and it has excellent characteristics on logs from numerous wells in the field. I'm looking forward to exciting times ahead from 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 just going to go over a few highlights of the second quarter and the year-to-date results, then we can 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's second quarter due to a 46% production increase and a 41% increase in average prices. Average production was up 46% to 4,690 BLE per day compared to 3,220 BLE 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 24 cents per share. compared to $2.9 million and basic EPS of $0.08 per share in the prior 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 quarter, which was an increase of 114% due to higher revenues partially offset by higher OPEX and a realized loss on commodity contracts. Our net back from operations increased to $43.92 per BLE compared to $29.66 per BLE in the prior 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 59 cents 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 in the prior year period. And this increase was again due to production from the wells that were drilled in the last half of 25. Debt income was $12.5 million and basic EPS was $0.35 per share compared to $8.6 million and basic EPS at $0.24 per share in the prior year period. The increase was due to higher revenue, partially offset by higher operating expense and depreciation expense due to the higher production, higher interest expense, and a realized loss on auto 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. Net vacuum 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. A continued increase in our borrowing base gives us more flexibility in managing our working capital going forward, and it also demonstrates the growing value of our property. 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. And we're looking forward to more growth with the four new wells coming online. We will now begin the question and answer session. To ask a question, you may press star then 1 on your touch-tone phone. If you are using a speakerphone,

Please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then two. And we'll pause momentarily to assemble our roster.

And the first question will come from Steve Ferrazani with Sidoti.

Please go ahead.

Morning, Wolf. Morning, Gary. Obviously, great quarter. Wolf, the surprise to us was the strength in the 2Q 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. 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 yeah, no, the wells are performing well. And, you know, when we bring these wells on, they flow for a while, then we put them on a lift. And so we got a little boost again when we put them on lift, you know, had a little decline and then came back up again on that. And now they'll start their normal decline after that as well. So, you know, we're not going to stay flatlined, unfortunately, until we bring the new wells on, which will go back up again.

When I think about that, were you still optimizing those wells within Q1? Is that part of the factor here?

Yeah, well, it's more along the lines of what I mentioned as far as bringing the gas compression in to the gas lift. That helps it out again, right? So you have some declines as far as 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.

Oh, wow.

But it just turned wells. But yeah, it goes back quite a few months, quite a few years, actually.

Got it. Got it. Okay. You provided the updated guidance late June. Were there any new factors that weren't included in that guide, Wolf, 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 three wells you're completing now. Any factors we should be thinking about that were not in that guide?

No, it'll just depend on how these wells do, that they're coming on, you know, the four wells. That's really the biggest factor on... But that's really what puts you from... Yeah, because it's a lot of production coming on at once, right? I mean, while our production has been growing nicely, right? We're close to 5,000. Yeah, absolutely. But still 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, 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.

Yeah, I understand.

Our guidance is what we have.

I'm trying to get you to anyway. Sorry, I'm not going to fall for it. No offense. But bigger picture, based on the guide, 3Q is 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 Levina well in general, so it's a two-mile well, you haven't done two-mile lateral, you haven't done that before. How much of that is because it's Wolf Regener, Steve Raunsbak, Allan Hemmy Wolf Regener, Steve Raunsbak, Allan Hemmy

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 one-mile laterals because we do have quite a bit of dip here. We've made this so that we don't have quite as much dip here. It's in a quiet area of the field where we don't see a whole lot of fault. We have good control around it, so we feel comfortable that we can push it to the two-mile out here on this well.

Got it. Well, it's an exciting time. What are the factors in deciding whether you'll complete it or not? Or we don't know?

Oh, I would imagine, unless we have a horrible drilling issue, that we'll be completing it. Which would then... I can't imagine any scenario where we wouldn't.

And would you be using, 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'll just be a matter of timing who's available for the right price too, right? So, but 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 Mac 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?

Yeah, the workover is definitely isolated to this quarter.

Well, it's actually the first half because it was in the first quarter as well. The workover from our non-op was both quarters. But yeah, it should stop now.

But the water hauling is shocking. I think it should be shocking how much was spent on one well. Yes, we were shocked.

And the water hauling, Gary, do you think that... and others.

The next question will come from Nicholas Pope with Ross Capital. Please go ahead. Hey Gary. Hey Wolf. How are you doing?

I've got a couple quick questions here on the operations front. Curious, with that Levina well, first test here in the Falls 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 y'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 cany wells that you're already drilling, maybe comparing it with that.

Yeah, so on a Thank you very much. So it's not as thick, and we have a lot of reserves in the cany, right? We have 40 million barrels proved in the cany itself. So even if the salt cany is thinner, even if you want to cut it in half, we're looking at something comparable that 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 will 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'll come down to just what the flow rates are from it and then what ultimately are the decline rates. But, you know, we've liked that core for a long time because it's a little thinner. We think the two-mile laterals really make the economics work really well. and, you know, our steering has gotten better and better with the newer tools over the last, you know, five, six years even. So we have high hopes that we're going to keep it where we want it, that 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, you know, then we'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 caning itself?

Or is it too early? It's really too early. I mean, I'm hoping we're making at least what the caning wells are. It might have higher IPs, maybe. But the terms 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, I'm curious if there's any concern about performance once those come back online when the CliftonMAC wells are done, or it's pretty straightforward? No, not at all.

Yeah, 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 that's the reason that they're shut in. We're drilling really close to where those other wellbores were, but it's the very toe end of those well bores that are hitting the heel of the Clifton Mac 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 Mac 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 and it slowly comes back over time. So I'm anticipating some flush production out of the Alicia Renee when they come back on.

Got it. All right. Well, that's all I had. I appreciate the time, Wolf. Oh, absolutely. Good to hear from you, Nick.

Again, if you have a question, please press star, then 1. Our next question will come from Richard Darnley with Longport Partners. Please go ahead.

Good morning. Clifton Mac 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 versus the standard average KU well?

Yeah, 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 to 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 was 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. It's always been kind of a tougher interval for us right out there. transition from the Springer into the K&E 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. Yeah, 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 and start getting fluid back out of the rock. So before that, we used higher mudweights 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. Okay.

is that classified info?

No, it's just we haven't discussed it, so I can't, whatever we didn't specifically put in a press release, I can't say on the call either, because otherwise we have to do another press release to disseminate that information. That's going to be difficult, but have to be careful about what we disseminate to everyone per the rules.

Right.

It would be useful to know that when you release the IP or EUR estimates, just for background.

I completely understand. But the good part is that no matter what these wells cost, we're still guiding toward our normal cany wells still being that same cost because in the rest of the field, we don't have to do these extra pacing strings. Right, right.

Is the gas-oil ratio heading north this quarter? Is that a one-off, or are your base wells getting gassier?

No, 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 if it was a press release or the MD&A.

In the MD&A. Yeah, 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 yeah, so we're tracking, like I said, 70 in the last few months.

Yeah, and basically the 74 that was in the first quarter was the new wells that came on had a higher percentage 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 All we're saying is that when you have whole core, our cany was oil saturated as well. So it's just an indication that there is oil in the false cany. 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.

Yeah, understand. Okay, thank you.

All right, good to talk to you. Thanks.

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, etc. Thank you, everyone. Have a great day.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.