Kolibri (KGEI) Q4 2025 Earnings Call Transcript

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DATE

Thursday, March 19, 2026 at 12 p.m. ET

CALL PARTICIPANTS

• President and Chief Executive Officer — Wolf E. Regener
• Chief Financial Officer — Gary W. Johnson

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TAKEAWAYS

• Production -- 4,013 BOE per day, up 15% from 2024, driven by new wells completed in late 2025.
• Compound Annual Production Growth -- 35% over the last 3 years, indicating consistent multi-year volume expansion.
• Net Revenue -- $56.9 million, a decrease of 3% as a 16% price decline more than offset higher production.
• Adjusted EBITDA -- $42.1 million, down 4% compared to the prior year's $44 million, reflecting weaker pricing.
• Net Income -- $15.5 million, with basic EPS of $0.44, compared to $18.1 million and $0.51 per share in 2024, attributed to lower revenues and higher absolute operating costs.
• Operating Expense per BOE -- $7.33 per BOE, decreased from $7.44 per BOE, reflecting a 1% reduction in unit costs.
• Netback from Operations -- $31.49 per BOE, down 18% from $38.54 per BOE, due to the impact of lower realized prices.
• Net Debt -- $46 million, with plans to reduce the balance in the first half of 2026 as higher production and increased oil prices generate stronger cash flow.
• Share Buybacks -- 650,000 shares repurchased for $3.2 million to date, with ongoing buybacks planned as working capital permits.
• Proved Developed Producing Reserves -- Increased by 30%, despite a substantial drop in evaluator-assumed oil pricing.
• Net Present Value of Reserves -- Up 10% even though the first-year price used in reserve calculations declined 18% to $58 per barrel.
• 2025 Drilling Program Impact -- Four wells completed late in the year raised December production above 5,600 BOE per day, with the primary financial benefit to be reflected in 2026 results.
• Cost Structure & Royalty -- Royalties average near 22%, varying by production location, and float with commodity prices.
• Hedging Program -- First-quarter hedges included costless collars for 16,000 barrels per day at $58.50–$77.25; April volumes are hedged at $94 per barrel for 16,000 BOE per day, with additional Q2 hedges in the $80s; second-half 2026 collars are set at $50.25–$66.75 and $61.50–$91, covering approximately half of current production.
• Unhedged Production -- Over 50% of production currently floats with market prices, with all incremental output from new wells fully unhedged.
• CapEx Framework -- Management expects 2026 capital spending to be "lower this year than it was last year by a long shot," with 3 wells comprising the base case (~$7 million each), contingent on oil price trends and board approval.
• Operating Expense Variability -- 2025 included some one-time workover costs, but overall wells remain "really low maintenance" per management.
• Market Outreach -- Management plans to increase investor outreach through participation in upcoming conferences and events.

SUMMARY

Management emphasized that 2026 results are expected to benefit significantly from higher volumes generated by late-2025 well completions and current favorable oil prices. Strategic flexibility was highlighted, with infrastructure in place to potentially expand drilling activity quickly if supportive market conditions persist. Capital allocation remains disciplined, as the share buyback program continues alongside prioritized debt reduction, and management communicated its intent to further enhance shareholder value through both initiatives.

• The company noted an ability to "quickly make changes" to operational plans due to its lean management structure.
• CEO Regener described the company's hedging posture as partially taking advantage of higher recent prices, while maintaining substantial exposure to further oil price increases.
• Four late-year wells, characterized as oil-rich and exhibiting slower decline rates, are expected to contribute disproportionately to near-term performance.
• No 2026 production guidance was issued, as management withheld specific targets pending greater operational visibility.

INDUSTRY GLOSSARY

• BOE: Barrels of oil equivalent; a volumetric measure aggregating oil, natural gas, and natural gas liquids based on energy content equivalence.
• PDP: Proved developed producing reserves; oil and gas reserves that are fully developed and currently producing.
• Netback: A per-unit measure of realized cash flow from production after operating and transportation costs, but before corporate-level expenses.
• Costless Collar: A risk management instrument combining a put and a call to define a price floor and ceiling for future commodity sales without premium payment.

Full Conference Call Transcript

Wolf E. Regener: Thank you, Dave, and thank you, everyone, for joining us today. With me on today's call is Gary Johnson, our Chief Financial Officer. As I'm sure you're all aware, we released our fourth quarter '25 results this morning and had released our reserve report 2 days ago, and we're very pleased with what we achieved this last year, which continues to build on our last few years and results in multiple ways. Production from the field has been going well with our production over 4,000 BOE a day, which is up 15% over 2024. This production rate calculates us to having a 35% compound annual production growth rate over the last 3 years, which is great.

Our operating expenses remain low with just over $7.33 per BOE, which is even lower than last year's $7.44 per BOE. Our drilling program last year resulted in our proved developed producing reserves increasing by 30%. And even though the oil price used by our reserve evaluators in Netherland, Sewell is down substantially this year, our net present value is up 10%. As an example of how significant the drop is, the first year's price used in the evaluation is down 18% to $58 a barrel. This is obviously way out of line with the current oil prices that's been averaging in the 90s right now. So things are going well for us.

And with that, I will turn the company -- the call over to Gary to discuss our financial results.

Gary W. Johnson: Thanks, Wolf, and thanks, everyone, for joining the call. I'm just going to go over a few highlights of our annual results for 2025, and then we can take questions at the end of the call. All amounts are in U.S. dollars unless otherwise stated. As we mentioned in our earnings release this morning, we reported a 15% increase in our production to 4,013 BOE per day in 2025. The increase was due to the new wells we drilled that completed during 2025, including 4 at the end of the year, which increased our December production to over 5,600 BOE per day.

The production and cash flow impact of the last 4 wells will primarily be reflected in our 2026 results. Our net revenue for 2025 was $56.9 million, which was a decrease of 3% compared to the prior year as prices declined by 16% in 2025, which more than offset the increase in production. Adjusted EBITDA decreased 4% to $42.1 million compared to $44 million last year due to the decrease in revenue. Net income was $15.5 million and basic EPS was $0.44 per share in 2025 compared to $18.1 million with basic EPS of $0.51 per share in 2024. The decrease was due to the lower revenue and higher operating expenses due to the production increase.

Our operating expense per BOE was $7.33 for 2025 compared to $7.44 per BOE in 2024, a decrease of 1%. Our netback from operations decreased to $31.49 per BOE compared to $38.54 per BOE in the prior year, a decrease of 18% due to the lower prices. Net debt at the end of 2025 was $46 million. We plan to pay down on this debt level in the first half of the year as we achieve higher production from the wells drilled at the end of the year, and we also benefit from the recently elevated oil prices. And then the last item I wanted to mention was our share buyback program.

We have purchased almost 650,000 shares since we started buying back shares for a total of $3.2 million. And we will continue to repurchase additional shares to enhance shareholder value as our working capital and credit facility allows. And with that, I'll hand it back to Wolf.

Wolf E. Regener: Thanks, Gary. As Gary laid out, we had a good year, where oil prices were obviously challenging and were lower in this last year than previous years, but we still performed well. The company is in solid financial shape, and we announced our intention to start drilling additional wells in the coming months. We're looking to continue the success we've had over the last year. That 35% compound annual growth rate for our production over the last 3 years has been great. The wells we brought on production late in the fourth quarter, as Gary indicated, are really having the biggest impact in 2026. And the timing of the oil price increase right now is really benefiting our cash flow.

Overall, our plan is to continue to execute and build and grow company value for all shareholders. As Gary said, continue to buy back shares, and we'll drill more wells. We'll continue to get the word out about the company to shareholders and potential shareholders, including we'll be attending the ROTH Conference next week, and we're doing a fireside chat at the Latam Summit on April 1 as well, and we'll continue to do other things throughout the year. This concludes the formal part of our presentation. We'd be pleased to answer any questions you now may have.

Operator: [Operator Instructions] Our first question comes from Steve Ferazani with Sidoti.

Steve Ferazani: Wolf, how are you thinking about -- obviously, a lot has changed in terms of the price environment over the last 3 weeks or so. How are you now thinking about the drilling program for this year as opposed to maybe how you were thinking about it pre-conflict or even what you were talking about late last year? I'm assuming the thought is maybe to drill more wells this year than maybe previously thought?

Wolf E. Regener: Yes. Cautiously optimistic is what I'll say. I don't know if the industry believes that these prices are staying up. It's -- we'll see how this all unfolds. As for most people, this is quite unexpected. We did take advantage of that a bit. So we did a bit more hedging at the higher prices, so that helps too. But as we are going forward right now, we're just planning on seeing how everything unfolds. I mentioned that we'll start drilling some wells here over the next coming months. And once we have firm dates on that, we'll announce that as well. We're building multiple locations out here. So that's always a longer lead time.

And this way, we can quickly move if we decide to extend the drilling program, drill more wells. But like I said, we're cautious in everything we do in general. And so it's very different this year. So I do think prices are going to stay higher than they were before, no matter what happens even if this ended tomorrow.

Steve Ferazani: I mean we know what the strip is to the end of the year. It would be very easy for you to -- and your balance sheet enables you to pivot pretty quickly if you did want to ramp up a little bit, right?

Wolf E. Regener: Right, exactly. So that's why we're doing the long lead items, making sure we have everything in place so we could quickly do things. And that's the big advantage we have being the size we have, right? We can start and stop much faster than some of the bigger guys that are more rigid in their financial structure, where we have a small board where we can quickly make changes to what we have proposed for the year.

Steve Ferazani: Got it. And then in terms of when you -- I know it changes in availability of crews, but it sounded like you indicated in the release, June would be when you might start this year's drilling program. Is that fair right now and would mean production probably early to mid-third quarter? Is that sort of the target?

Wolf E. Regener: Yes. I mean, hopefully, we'll see how things go. Hopefully, we can get started a little sooner than that. But yes, I'd like to keep the June out there until we have everything firmed up. So I'd rather underpromise.

Steve Ferazani: Yes. Understood. Understood and things change fast, right? A couple of numbers surprised me in the quarter. The realized natural gas price. I know that moves quarter-to-quarter and again, the differential can move. It seems a little bit lower than I would have expected.

Wolf E. Regener: Yes. That's really hard for us as well because we sell all of our gas and our wet gas, which is our gas and natural gas liquids and Exxon handles that. And so where that goes and as far as how much gas is sold out versus how much NGLs and things like that are all in their hands. And we're always assuming that we get the best price that is available because they're doing the same thing for their own account. But it does fluctuate, and it's hard for us to forecast that as it is for you, unfortunately.

Steve Ferazani: I understand. And then the slightly higher...

Wolf E. Regener: It's not a big part of our stream, thank goodness.

Steve Ferazani: Right. Absolutely. Absolutely. And then the higher production operating expense, I think you noted the fourth quarter. The workover, that should be onetime in nature, right?

Wolf E. Regener: Correct. That's exactly right. And for the year, we were still looking great, and we do have budgeted reworks throughout the year. It just depends on when they come in. And if it's multiple in a quarter, then our wells are really low maintenance, we're lucky on that. So -- but we need maintenance from time to time.

Steve Ferazani: Understood. In terms of -- you noted a lot of the -- there were oil-rich wells you brought online mostly in the second half of '25. You previously noted the much slower decline rates. Is that playing out over the last few months?

Wolf E. Regener: Yes. I mean we're -- yes, I mean, we haven't seen a change. We're happy with how those wells are performing. I think Netherland, Sewell over the years has been increasing what our decline rates or the decreasing the decline rates, I should say, over the years. And so on the newer wells, they usually hit those a little bit harder and then in the following years, they kind of bring it up a little bit because they do perform well. We expect the same thing out of the wells we drilled last year.

Steve Ferazani: Got it. And last one for me. You may choose not to answer it, but given that it's March 19, can you give any sense of what 1Q production might look like?

Wolf E. Regener: Yes. No, we haven't put that out there, so I can't really speak to that on this call, unfortunately.

Operator: And the next question comes from Poe Fratt with Alliance Global Partners.

Charles Fratt: Can you give me at least a ballpark on your CapEx for 2026?

Wolf E. Regener: We haven't put anything out there, so I have to be careful. What I've said in the past is kind of my goal and speaking just for myself, not from our Board approved or anything else, is to keep this production flat to growing a little bit in general expense, but that shouldn't take more than 3 wells or so. So that's kind of as close as I can get without -- from my own opinion as far as what we should do for -- at least do for the year. Now that oil prices are higher, we'll probably be higher than that. But if we add more wells, it adds a lot.

And so our wells are in the roughly $7 million range each. It just depends on how many we end up drilling for the year. So -- but once we have that pinned down, we'll put that out precisely. But our CapEx will be lower this year than it was last year by a long shot, unless we really accelerate what we're doing out there.

Charles Fratt: Yes. And I guess closer to 2024, the full year CapEx for 2024, maybe even lower than that?

Wolf E. Regener: Yes. I mean, going -- as we had talked about earlier, it's like we were going into this kind of talking about what we're doing with oil prices being a lot lower than they are. And with that lower oil price number in mind, I think from my point of view, I think it will end up being reasonable to drill 3 wells or so at least. So that's in the low 20s. And then if oil prices stay higher, I anticipate that we would recommend and the Board would agree that we should drill some more wells. So that would increase the CapEx quite a bit.

Charles Fratt: That's helpful. And I apologize, I couldn't find any info on your hedging program. Can you just summarize your hedging program for the first quarter and then the full year?

Wolf E. Regener: Gary, do you want to take that? You probably have that in front of you.

Gary W. Johnson: Yes. Well, the first quarter, we didn't really hedge much recently because it was already in March when the prices went up. So for the first quarter, we have costless collars in place. We're about 16,000 barrels of oil per day. The costless collar range is $58.50 to $77.25. But we have hedged in April, we have a fixed price swap at $94 for 16,000 BOE per day. And then we've also hedged next May and June as well in the 80s. We've basically done as much hedging as we're allowed to do on our credit facility right now for the second quarter.

Wolf E. Regener: Yes. And those hedges were about 500 barrels a day, wasn't it, roughly?

Gary W. Johnson: Yes.

Wolf E. Regener: Just In rough numbers.

Gary W. Johnson: Yes, rough numbers, yes.

Wolf E. Regener: We have a substantial amount of our production that's not hedged, I'd say, over 50% that's free floating still.

Charles Fratt: So is the second half production pretty much open right now?

Wolf E. Regener: No, we still have hedges there. We still have some old hedges from the costless collars, right? And then we added some other costless collars. Go ahead, Gary.

Gary W. Johnson: Yes. So we put in some more costless collars for the second half of the year. So we have about half or these were entered into, obviously, before the price uptick or $50.25 is the low and $66.75 is the high. And then we just did new ones where the low is $61.50 and the high is $91. Those are costless collars and those take place across the rest of the year.

Wolf E. Regener: Right. And that's -- again, that's 50% roughly of our current PDP. So anything new that we drill is completely unhedged.

Charles Fratt: Great. And then when you look at your cost structure for 2026, any changes that you could highlight? I'm wondering about the royalty per barrel. It looked like it was pretty low in the fourth quarter. Is that sensitive to prices? Or just can you help me understand how that might move in '26?

Wolf E. Regener: So the royalty percentage changes a little bit depending on where the majority of our production coming from because each square mile out here has a different royalty structure. But in general, we're averaging 22-ish percent burdens on everything. And then the dollar amount would float up and down with pricing because it is a percentage.

Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Wolf Regener for any closing remarks.

Wolf E. Regener: I just want to say thank you, everyone, for participating and those of you that will hopefully listen to this later as well. And we're looking forward to having a really good 2026 year. And I think we're off to a really good start between our production levels and the pricing, which is helping out. So thank you, everyone, very much. Have a great day.

Operator: Our conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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