Thank you. 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, 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, production, and adjusted EBITDA in the history of the company.

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 Mac wells, and looking forward to beginning the completion operations on those shortly.

I'm also very excited that we're starting to drill the Lubina 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 showed 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 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 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 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 24 cents per share compared to $2.9 million and basic EPS of 8 cents 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 year quarter, which was an increase of 24%. This increase was due to workover costs for a non-operated well, which added 59.10 cents per BOE, and also temporary higher water hauling costs compared to '25.

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.

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 35 cents per share compared to $8.6 million and basic EPS of 24 cents 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 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.

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.

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 with the four new wells coming online. In addition, as I said in the beginning of the call, also really looking to this 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 have now.

Morning, Wolf. Morning, Gary.

Obviously, great quarter. Wolf, the surprise to us was the strength in the 2Q production and the fact that there 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 just did well. Yeah.

No, the wells are performing well. When we bring these wells on, they flow for a while and then we put them on a lift.

We got a little boost again when we put them on lift. Had a little decline and then came back up again on that.

Now they'll start the normal decline after that as well. We're not going to stay flatlined unfortunately until we bring the new wells on, which will go back up again.

Yeah.

That's all that's

going on.

When I think about that, the 4Q wells, was it the Barnes and the Velin, were you still optimizing those wells within 1Q? Is that part of the factor here?

It's more along the lines of what I mentioned as far as bringing the gas compression in to the gas lift, and that helps that out again, right? You have some declines

that

start happening and then you can reverse some of that when you bring that on. Yeah.

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. It's just certain wells.

It goes back quite a few months. Quite a few years actually.

Oh, wow. Okay.

Got it. You provided the updated guidance late June.

Were there any new factors that weren't included in that guide, Wolf? 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 as they're coming on, the four wells. That's really the biggest factor on our guidance, yeah, because it's a lot of production coming on at once, right?

While our production has been growing nicely, right? We're at close to 5,000.

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 of effect. Absolutely.

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, it's reasonable to start thinking probably the low end is less low risk.

I don't want to overpromise anything, our guidance is what we have. Sorry, I'm not going to fall for it, no offense.

I understand. I'm trying to get you to anyway.

Bigger picture, 3Q is, 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. Then is the Lubina well in general, 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 in the False Caney, or how much of it is the geographical location in the field? What's allowing you to try the two-mile lateral for the first time?

Even on these mile-and-a-half laterals, some of them are a little bit longer because we're sometimes coming into a section back a bit. Some of these mile-and-a-half were actually a little bit longer.

Really, it's a quiet area. We've been able to steer still at the end of our laterals.

Now 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 faulting. We have good control around it.

We feel comfortable that we can push it to the two-mile out here on this well.

Got it. 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, we'll be completing it. I can't imagine any scenario where we wouldn't.

Which would then And then the plan would be the And the

would you be using that timing-wise, would you be using the same spread?

I don't know if it's going to be the same or not. It would just be a matter of timing, who's available for the right price, too, right?

It is a timing issue as well. 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?

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 yeah, it should stop now.

The water hauling,

it's too shocking how much was spent on one well.

It should stop now. We were shocked.

The water hauling, Gary, does that temper here or is it around this level for the year?

It's definitely gone It's definitely gone down throughout the quarter, I mean throughout the year so far, but I mean it's might be it's probably going to be higher than last year a little bit, but not too much, but definitely going to temper down.

Got it. 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 and up, and so we've putting actually some physical things in to try to knock those chemical costs down again.

We're in early stages of that. We think we're making some progress on that.

There's been some cost escalation, but nothing too bad.

Got it. All right.

Thanks, Wolf. Thanks, Gary.

Absolutely. Thanks, Steve.

Hey, Gary. Hey, Wolf.

How are you doing?

Hey, Nick. Doing

good. How are you?

Good. Got a couple quick questions here on the operations front.

Curious with that Lubina well, first test here in the False Caney, said you had that whole core look oil-saturated. Curious I guess what's remaining for 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'd 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?

Yeah. On a prospective basis, the zone's a little thinner.

You can see that on our presentation too with how it's more cartoonish, but it is relative to one another. It's a little thinner than the Caney itself.

If you look at how much acreage we have in our proved reserves for our Caney itself, that's 11,500 acres net to us, and the Caney we think has prospective over about 9,900 acres. 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. Even if the False Caney's 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.

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, 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. 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. Our steering has gotten better and better with the newer tools over the last 5, 6 years even.

We have high hopes that we're going to keep it where we want it. That our GLD is going to be good and it should be with the control we have.

That will make a good well. Then it'll be what the flow rates are and what the 30-day rate is and how she declines thereafter.

I'm hoping it's very definitive right off the bat.

How are you expecting the initial rates to compare to the Caney itself? It's too early.

It's really too early. 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 bit better, but we'll see. Let's let the production speak for itself when we do it, I don't want to lead anyone too much one way or another on this.

Got it. Appreciate that, Wolf.

Then looking at these Alicia Renee wells that are shut in.

Right.

Curious if there's any concern about performance once those come back online when the Clifton Mac wells are done or is pretty straightforward that well?

No, not at all. Yeah.

It's just the way we had to redesign the programs, we had to drill them closer in to where those were just to get around some of the faults that we found when we drilled that first one. 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 wellbores that are hitting the heel of the Clifton Mac wells. Even if we frac 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.

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.

I'm anticipating some flush production out of the Alicia Renee when they come back on.

Got it. All right.

That's all I had. I appreciate the time, Wolf.

Oh, absolutely. Good to hear from you, Nick.

Good morning. The 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? Or versus the average Caney well?

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. 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.

We had to put an extra casing string across that to isolate that. Then there was some higher pressures down at the bottom, 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 a kind of a tougher interval for us right at that transition from the Springer into the Caney formation. 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.

It showed us higher pressures. I don't have a quantifiable number on that.

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.

Before that, we used higher mud weights here to drill it to keep everything in place. That's the reason for the higher pressures that we mentioned.

Right. What did they end up costing?

We haven't specified it specifically, but they were more expensive than our normal wells, so.

Is that classified info?

No, it's just we haven't disclosed it out here. Whatever we didn't specifically put in the press release, I can't say on the call either because otherwise we have to do another press release to disseminate that information.

That makes it 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.

Completely understand. 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.

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

No, part of it is this adjustment that came in that dropped it down a bit lower as well. You'll see we have a note, I can't remember if it's the press release or the MD&A that

In the MD&A. It was 70% in May and in June, so that's skewed by that adjustment for the quarter.

That's why it was really low, but yeah, we're tracking 7, like I said, 70 in the last 2 months.

Basically the 74 that was in the first quarter was the new wells that came on had a higher percentage oil oil percent. While the oil is tracking what the decline has been, we did start getting additional gas coming in.

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.

Right. Okay.

You said that you expect the False Caney well to be oil-saturated. Your base is very oil-saturated already.

Are you expecting higher oil saturation from the False Caney?

No, we won't know what the percentages until we drill it. All we're saying is that when you have whole core, our Caney was oil-saturated as well.

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 it back.

Understand. Okay.

Thank you.

All right. Good to talk to you.

Thanks.

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.