Good morning everyone, just a few administrative points before we jump into our presentation. We will be recording today's call and we will have a replay available on our website later on today.

All attendees have been placed in listen-in only mode for the duration of the presentation. We will have a Q&A session at the end of our presentation and you can start logging any questions that you have using the Zoom Q&A button that you should see on your screen.

If you've dialed in by phone, you can also send any questions to [email protected]. Lastly, we will be going through various non-GAAP measures and making forward-looking statements throughout this presentation, we do encourage you to read through all of the disclosures and cautionary statements that we have both in our corporate presentation on our website, as well as in our MD&A that is also on our website.

Great. Thank you, Alison.

If you recall, at the beginning of 2025, we did upgrade our gas sales agreement, and then when we combined that with some of the strength that we demonstrated on our Murucututu project, particularly with the 183-D4 well, we were able to deliver some pretty strong results in 2025. Our production was up 41% year-over-year and we exited the year with a record quarter, 2,867 barrels of oil equivalent per day in the fourth quarter, and we're pleased to say that we had an even higher record quarter in Q1 of this year that we just announced, along with the financial results here at over 3,100 barrels of oil equivalent per day.

We did upgrade our gas sales agreement again at the beginning of 2026, increasing our firm supply again by another 25%. If you compare Q1 on a quarter-over-quarter basis, we were up 9%.

If you compare Q1 to our 2025 average, we're up about 25%. Pretty strong start, and you can see we just recently announced our April production as well, which continued at a pretty consistent level to Q1.

Lastly, I think, if you consider this growth that we've been able to generate over this period of time, I think it's pretty impressive, especially when you consider it in the context of the fact that we're paying out about half of our cash flows in returns to stakeholders.

Jumping into our Q1 2026 results that we released, starting with our operating netback, that is a measure of our operating profitability, and we measure it in per barrel of oil equivalent. Just a reminder to calculate that, we start with our realized sales price, that's at the top of the chart, we deduct off royalties, that's the orange bar.

We've combined production and transportation expenses, that's the gray bar, and then the green bar is our operating netback. Looking at Q1, we had a realized sales price of $61.77.

That was up over $2 from Q4 2025. Included in that, our natural gas sales were just over $10 per mcf at $10.14.

Our royalties of $4.19 is an effective royalty rate of just under 7%, which is consistent with last quarter, 6.4% in Brazil and 13.6% in Canada. Production and transportation costs decreased both overall in terms of dollars and also per boe with that increased production.

They were down 76 cents per boe, or about 12% from Q4, and our operating netback with all of those improvements was up $2.42 compared to Q4, Brazil netback just over $53 and Canadian netback just over $36. That translates into an operating netback margin when you look relative to our realized price of 84%, and again when you compare that to other companies operating in South America and in North America, that's really industry-leading netback margins.

If you layer in the fact that we qualify for the SUDENE tax incentive in Brazil, which reduces our effective rate to just over 15%, and we actually have no current tax in Canada right now because we have tax pools to offset our earnings here, that really allows us to generate funds flow from operations on this base level of production. On the funds flow from operations, this chart here just compares our Q4 of $10.6 million to Q1 of $12.5 million, we were up $1.9 million.

The bulk of that is increase in revenues both in terms of our sales volume increase as well as our realized price increase. As I mentioned as well, production expenses were down on a dollar basis compared to Q4.

Our interest and other income was higher than Q4, G&A was down, and then partially offsetting that was higher royalties, with those higher revenues, and also higher current tax. Very strong quarter here at $12.5 million funds flow.

Similarly, on net income, we saw an increase of $2.5 million. That's again impacted by all those same things that funds flow was impacted by.

Also saw an improvement on our FX, there was higher FX gains this quarter of $1.7 million, or the change was $1.7 million compared to losses last quarter. Offsetting that, we did have higher depletion and depreciation, finance expense, and also deferred tax.

Overall, net income of $8.1 million this quarter.

As a reminder, we did declare again a 12-cent U.S. per share dividend in the first quarter.

This just shows the dividend history since we introduced the dividend in the third quarter of 2021. That dividend translates into a current yield of about 7.6%, and in total, since inception, we've now paid dividends of nearly $2 per share or over $70 million back to shareholders.

This slide just highlights our more disciplined capital allocation model where we're basically trying to take roughly half of our cash flows and return it to stakeholders and take the other half and reinvest it in growing our business. The chart that you see on the left here, all the green lines with the black dots show all the cash funds flow from operations each quarter, the cash inflows each quarter.

As Alison just highlighted, $12.5 million for the first quarter of 2026, which was up 18% over the fourth quarter of last year. Then all the stacking bars just show the cash outflows in each particular quarter.

All the various shades of green are the various returns to stakeholders, and the yellow are the capital expenditures that we've been making in each individual quarter. The pie on the right-hand side just shows in total since July of 2020 we've now had cumulative funds flow from operations of $217 million U.S.

Of this, just over half has been reinvested and just shy of half has been returned to stakeholders in these various forms, so. We have announced some upgrades to our gas sales agreement recently, and this graph just kind of highlights the fact that we've got two different pricing formulas under our firm sales to Bahiagás now.

The red line is the kind of historical contract that we've had. We're currently selling about 80% of our gas under this formula in red, and then at the beginning of 2026, we added another firm layer of gas sales under this QDC2 formula, which is this orangey brown color at the bottom here, about 20% of our sales on that.

Then when we do a weighted average of the two, it's the green line that you see here, which becomes our weighted average realized price. You can see the price gets adjusted quarterly, we most recently announced our May 1st price, which was using Q1 2026 commodity prices up to over $11 per mcf.

Then if we use the futures market for the forecast period, to the right of this dashed line that you see here, you see another forecasted sharper increase forecast for August 1st on a combined basis of over $13 U.S. per mcf.

Then we have also added the formulas down below. The red line, the original contract we had, the way the formula works is we have a fixed component that does get indexed to inflation, and then the variable component is based kind of half on a function of Brent and the other half on a function of Henry Hub, a premium to Henry Hub plus another fixed margin that also gets adjusted for inflation.

We calculate a U.S. dollar per mmbtu price, and then for our gas, which is kind of hotter than average, we apply this factor to get to a U.S.

dollar per mcf price. Then you can see for QDC2, it's entirely a function of Brent, which is a little bit different, and I think that covers it.

We've established a strong platform in Brazil and now our activity is focused on our next growth objectives. Our biggest growth opportunity is our 100% 100% working interest Murucututu project, which is just north of Caburé.

We made a significant discovery on this block with our 183-A3 well and then the 183-D4 follow-up well. And 183-D4 came on production last August, well ahead of expectations, and the production from this well continues to be strong through the first quarter of of this year.

We have a facilities-focused 2026 plan to unlock the potential of this asset and set this stage for the next phase of growth in this area. First, we are going to quadruple the Murucututu takeaway capacity for the field itself, and then we're also expanding our gas plant, or UPGN Caburé, to add the processing flexibility to facilitate this Murucututu growth.

We have a combination of reserves and resources with GLJ that demonstrates this potential of this Murucututu asset, and we're working to migrate this into production and cash flow to support our longer-term growth objectives. At the field itself, we're well underway with our 2026 development plan.

We're increasing the field processing takeaway capacity fourfold for this field. We're in the procurement process of the main processing equipment for this field expansion, and we're looking forward to installing this equipment over the next coming quarters.

We're also expanding the field egress by increasing the pipeline capacity of up to 600 e3m3 a day. To do this, we're going to loop the existing 4-inch pipeline with an 8-inch pipeline.

Currently, we're in the permitting process of this, and the line pipe itself is being manufactured in Brazil. At the field itself, we're also drilling a follow-up well, a 183-D1 well, which is right where the cursor is there.

We started this project at the end of April, we're right in the middle of the drilling project right now. We're going to be completing this as soon as practical, once the rig leaves, we can bring on the completion equipment and tie that into the existing pipeline facilities.

This development well will add additional production capacity for this field. Also currently, we're building a G-pad, which is right where the cursor is there, and so this is a location that's going to support up to four additional Caruaçu development locations.

This pad is going to be pipeline connected as we do our other looping project. The second phase of development that we're focusing on in 2026 is our midstream project at UPGN Caburé itself.

This year, our plan is to optimize the processing capacity of this facility to improve the ability to increase additional amounts of Murucututu gas, which is hotter gas. The target capacity of this project is an overall gas plant rate of 600 e3m3 a day, but will allow up to 300 e3m3 a day of Murucututu gas to be blended with our Caburé gas.

This project has already been initiated with our facilities partner, Enerflex, and we expect this to be online at the end of the third quarter. This project will allow us to substantially increase the amount of offtake from our Murucututu asset.

All right. Moving on to Western Canada, I think everyone is probably aware that we announced a strategic re-entry into the Western Canadian Sedimentary Basin through two transactions last year, which culminated in an area of mutual interest highlighted in green on the map that you see here, which basically covers the entire Saskatchewan side of the Mannville stack heavy oil play fairway, also with some recent land acquisitions that brings our land holdings to over 100 square miles of land on a gross basis, we're 50% interest in that, over 32,000 net acres of land.

We've now got 3.5 net wells on production. We did have some initial reserve recognition from our independent reserve evaluator, GLJ, at the end of last year based on the limited amount of activity that had happened to that stage, 735,000 barrels of oil equivalent with an NPV of just over $12 million.

They were able to assign just eight gross or four net undeveloped locations to the asset based on the drilling at that point, but you'll see on the next slide this just highlights that. Through the early process, we also really helped delineate three core areas: Neilburg, Salvador, and Lashburn.

That's where the eight undeveloped locations that GLJ assigned reside, but you can see we have an inventory of over 100 locations that we see. The type curves that GLJ assigned on a 2P or proved plus probable basis for the three different areas are highlighted on the graph here with initial production rates somewhere between 110 and close to 150 barrels of oil per day on a gross basis, and cumulatively producing over the life of the well between 100 and 175,000 barrels per well.

We certainly think that we've built another substantial area for growth for ourselves here. If you use even just a $70 flat oil price forecast, the rates of return that these types of projects would generate, we're targeting between 50% and over 100% IRR, it's pretty compelling and gives us good exposure to oil prices.

Just to wrap up this part of the call, to reiterate, I think we had a pretty amazing year last year and we continue to deliver some pretty strong results to start off 2026. We continue to benefit from very attractive natural gas prices, industry-leading operating netbacks and operating netback margins.

In addition to the strong production growth that we had through to date, even April of this year, just as a reminder, we also were able to generate some pretty substantial reserve growth, over 43% increase in our 2P reserves even after considering that we produced close to 1 million barrels of oil equivalent last year and replaced production over five times. The strong free cash flow generation capacity that we have really does help underpin the more balanced and disciplined capital allocation model that we have.

For value investors, trading at about 60 or less than 60% of our 2P NPVs. For yield investors, that U.S.

12-cent per share dividend translates into a 7.6% dividend yield at current prices. For growth investors, I think we have a pretty exciting capital program ahead of us and looking to unlock a lot of value, especially when you consider it relative to our existing enterprise value.

The nice thing is we now have growth opportunities both in Brazil as well as an attractive inventory of heavy oil drilling opportunities in Western Canada. Obviously, we had another record quarter to start off 2026 at over 3,100 barrels of oil equivalent per day, which was up another 25% from an already very strong year last year.

Then the capital program that Adrian walked through earlier really helps put the pieces in place to give us the opportunity to deliver another 20-plus percent year-over-year growth potential for 2027. I think, like I said earlier, I think if you can consider that in the context of paying out half of our cash flows to stakeholders, it really is quite exceptional, especially when you compare it to virtually all of our peers, so.

With that, we'll start the question-and-answer period. If you haven't had the chance, please log your question into the Q&A portal.

We have a few questions in here. How much capex will you have in 2026 and how much in Brazil for infrastructure versus drilling?

We announced a capital budget in February for Brazil of roughly $21 million. We did kick off some projects in Q1, but there's probably still approximately $19 million of that remaining.

From the facilities and pipeline, I think we are forecasting approximately $7 million, and then we of course are drilling this 183-D1 well right now, and that is what is included so far in the plans for Brazil, but obviously we are in a position to accelerate capital spending and accelerate wells as we see fit with our strong cash position right now. You have a very strong balance sheet position and we are in a positive macro environment.

How do you think about capital allocation in particular of the excess cash flow versus what would have been expected pre the Iran conflict?

Yeah. I think our capital program in Brazil in particular is pretty well established.

I think the balance sheet combined with we've had a pretty big increase in production if you combine that with the gas price expectations that I showed on the slide earlier, it's natural to assume we're going to have pretty strong cash flow projections as we move through the year. We have a lot of flexibility from that and the balance sheet, which, if we decided to accelerate some of our planned 2027 drilling into 2026 in Brazil, for example, we have the flexibility to do that.

Those are the types of decisions we'll make as we progress through the current drilling operation. In Western Canada in particular, obviously those higher oil prices really help improve the rates of return that I alluded to earlier, we are working with our partner to build out our next phase of drilling for the Western Canadian asset, and I think we have a lot of flexibility to expand that.

This sort of follows on to that. What will determine the pace of investment into Canada as the returns should be very strong given the current oil price?

Will you look to hedge to lock your returns if prices stay around current levels, and are there any constraints in terms of oil service drilling capacity to execute?

No, I think based on all the work that we've done to date, there's ample availability of services. I think the natural drilling window just the way Canadian breakup works and all that would be a program that would be in the summer here.

We wouldn't see any real impediments. We are trying to work collaboratively with our partner to lay out that program, but like I said, I think we have a lot of flexibility as we move through the year.

On the Murucututu asset, can you explain why you think you experienced low reservoir inflow in the lower Gomo interval in your 183(1) well and any read-through to future drilling?

We are continuing to evaluate the results from this specific well. As we focus our development at the Caruaçu reservoir, we plan to drill all or some of these wells into the Gomo reservoir as well, and we will look to complete those wells similar to how we've completed the 183-D4 well last year.

We do remain confident that we have a large potential resource in the Gomo to develop.

For the 183-D1 well that you're drilling right now, what are your expectations in terms of production rate?

The D1 is an offset to D4 and A3, from a reserves perspective, this is a development well, we'd expect it to be similar to what our other wells came online at,

but. Do you see any opportunities for M&A in both or either country in 2026?

The short answer is yes. We don't usually talk about any detailed kind of business development plans.

To be frank, there's probably a lot more opportunity in Western Canada, certainly a lot more operators and we're certainly seeing a lot more product, let's say, being offered. Anything that's happening certainly in our basin in Brazil is an obvious strategic fit for us as well.

Are there any plans to hedge prices this year?

We've got a pretty strong balance sheet, and the rates of return on the projects that we're talking about in Brazil, I don't think we really need to do that, but it's something we'll continue to evaluate.

Let me just double-check. I think that's it for questions right now.

All right, well, as usual, if you have questions after the fact, feel free to reach out to any one of us and we look forward to updating you next time around after our Q2 results. Thank you again.