Thank you, Shannon. Good morning, and welcome to Gran Tierra's fourth quarter and year-end 2025 results conference call.

My name is Gary Guidry, Gran Tierra's President and Chief Executive Officer, and with me today are Ryan Ellson, our Executive Vice President and Chief Financial Officer, and Sebastien Morin, our Chief Operating Officer. Yesterday, we issued a press release that included detailed information about our fourth quarter and year-end 2025 results.

In addition, Gran Tierra Energy's 2025 annual report on Form 10-K has been filed on EDGAR and is available on our website. Ryan and Sebastien will make a few brief comments, and we will then open the line for questions.

I'll now turn the call over to Ryan to discuss our financial results.

Thanks, Gary, and good morning, everyone. The company has recently successfully executed a bond exchange of our 9.5% senior secured amortizing notes due in 2029 with a participation rate of approximately 88%, demonstrating high investor confidence in the company's strategy.

Combined with our prepayment agreement and recent Simonette disposition, we are entering 2026 with a meaningfully enhanced liquidity position and a stronger balance sheet. Subsequent to year-end, we amended and expanded our existing prepayment agreement, adding up to $175 million of incremental capacity plus $25 million accordion, and was our primary source of liquidity to support the 2029 notes exchange.

Concurrently, we terminated our Colombia credit facility; however, kept our $75 million Canadian facility in place. Importantly, this improved maturity profile, enhanced liquidity position, allow us to shift from near-term refinancing considerations to disciplined, opportunistic debt reduction with extended runway provided from the debt exchange, we can actively pursue bond buybacks at attractive discounts while continuing to allocate capital to the highest return development opportunities across the portfolio, accelerating deleveraging without sacrificing asset progression or long-term value creation.

Additionally, we are very pleased to announce our entry into Azerbaijan, which we view as a compelling and a capital-efficient addition to our portfolio. Partnering with SOCAR provides an early, scaled entry into a stable and supportive jurisdiction with established infrastructure and a long production history.

This opportunity aligns with our strategy pursuing risk-mitigated growth in proven basins where our operating model and technical expertise can drive value. Given Azerbaijan's role in supplying energy to European markets, we see meaningful long-term strategic potential from this entry.

From a hedging standpoint, we continue to layer in hedges to support cash flow stability in 2026. Oil volumes are approximately 50% hedged throughout the year using a mix of three-ways, collars, and puts with an average floor around $60, balancing downside protection with upside exposure.

For gas, we have AECO swaps covering, on average, 14,200 GJ per day at approximately $2.77 per GJ for 2026. Our 12-month rolling program maintains disciplined coverage levels while preserving price upside.

Turning now to our financial results for the year. During 2025, Gran Tierra realized a net loss of $193 million or $5.45 per share, which included non-cash ceiling test impairment losses of $136 million, compared to net income of $3.2 million or 10 cents per share in 2024.

Gran Tierra's capital expenditures increased slightly by $8 million or 3% to $256 million compared to 2024 due to a higher number of wells drilled during the year in Colombia, Ecuador, and Canada. The company realized adjusted EBITDA of $284 million, a decrease of 23% from $367 million in 2024.

2025 funds flow from operations were $178 million or $5.02 per share compared to $225 million in 2024. Both these decreases were commensurate with the decrease in Brent oil price.

The company generated net cash provided by operating activities of $313 million, an increase of 31% from $239 million in 2024. The company had $83 million in cash and cash equivalents as at December 31st, 2025, a decrease compared to a cash balance of $103 million as at December 31st, 2024.

In addition, the company has its Canadian credit facility fully undrawn with a capacity of $75 million Canadian. During 2025, the company bought back $21.3 million face value of the company's 2029 senior notes.

Gran Tierra's net oil and gas sales for the year were $597 million, a slight decrease of 4% compared to 2024. Total 2025 operating expenses were $249 million compared to $202 million in 2024, representing a 23% increase, while operating expenses per BOE were $15.17, 6% lower when compared to 2024.

The increase in total operating expenses in 2025 was a result of higher operating costs in Ecuador, driven by a production ramp-up in 2025 and a full-year contribution from our Canadian operations. Taken together, we have had a very busy start to the year with all these corporate actions, repositioning the company for a strong 2026 and beyond.

I'll now turn the call over to Sebastien Morin to discuss some of our highlights of our current operations.

Thanks, Ryan. Good morning, everyone.

I will start with our 2025 year-end reserves. On January 28th, 2026, we announced our year-end reserves as evaluated by McDaniel.

The results reinforce the strength, depth, and optionality embedded in our portfolio. In South America, we delivered greater than 100% reserve replacement on both a PDP and 2P basis, driven by exploration success and strong asset performance.

For 2025, we reported 142 million barrels of oil equivalent of 1P reserves, 258 million barrels of oil equivalent of 2P reserves, and 329 million barrels of oil equivalent of 3P reserves. South American reserve replacement was 101% for PDP, 61% for 1P, and 105% for 2P.

These outcomes were supported by multiple exploration discoveries in Ecuador, disciplined management of our low-decline Colombian assets, and successful integration of our Canadian operations into a diversified, multi-basin portfolio. In Canada, certain natural gas reserves were reclassified to contingent resources due to current low gas prices under reserve booking standards.

As operator of the majority of our assets, we retain the flexibility to reallocate capital toward high-return, quick-payout gas developments in a stronger price environment, and we remain constructive on long-term natural gas demand given LNG expansion and structural growth in power demand. Our PDP reserves continue to generate meaningful cash flow that supports deleveraging, while our broader inventory, including approximately 0.3 Tcf of unrisked 3C contingent resources in the Glauconitic formation and 0.4 Tcf of 3P gas reserves across our Canadian assets, provides substantial long-term gas development optionality.

The organic and inorganic growth achieved over the past several years has created a runway of highly economic development opportunities in proven plays with established infrastructure. With Canadian operations now fully integrated, approximately 18% of production, 19% of 1P reserves, and 22% of 2P reserves are attributable to natural gas, and Canada represents 39% of 1P and 44% of 2P reserves.

This diversification enhances resilience across commodity cycles while preserving capital allocation flexibility. From a valuation perspective, year-end 2025 NAV per share was $22.61 before tax and $13.61 after tax on a 1P basis, and $51.09 before tax and $31.17 after tax on a 2P basis.

Compared to our current share price, this reflects a meaningful discount of 2 to 5 times across all NAV categories. In terms of production, Gran Tierra achieved 2025 average working interest production of 45,709 barrels per day, representing a 32% increase from 2024, due to a positive exploration well drilling results in Ecuador and full-year production from our Canadian operations, which was partially offset by lower production in southern Colombia and Ecuador as a result of two major export pipeline disruptions and the Moqueta field being shut in due to trunk line repairs during the third quarter of 2025.

Operationally, we are building off a successful year in 2025 to start off 2026 on a strong note. As Ryan noted previously, with the company fulfilling all 2025 Ecuador commitments and the Suroriente carried work program well underway, we are entering a new phase focused on generating cash flow and maximizing the value of our diversified portfolio.

From a development standpoint, we are excited to share that we recently drilled the Rahu-2 well on the Suroriente block, targeting the northern extent of the Cohembi field. The well is producing approximately 790 barrels of oil per day at less than 1% water cut and is performing ahead of our initial expectations.

The result further delineates the field and supports the broader development potential of Cohembi to the north. Rahu-2 also advances our Suroriente capital carry commitment, which we expect to complete by mid-2026.

To close, our operational focus remains on portfolio longevity, asset quality, and disciplined execution. With the addition of Azerbaijan, our portfolio now spans 4 countries, 6 basins, and 3 continents, further enhancing diversification.

The company continues to be supported by a strong PDP foundation, meaningful 1P and 2P reserves, and a consistent track record of progressing resources from 2P to 1P and ultimately into producing assets. As we advance our operational and financial objectives, we remain steadfast in our commitment to safe, responsible operations and supporting the communities in which we work.

With a stronger capital structure and a clear focus on free cash flow and debt reduction, we believe 2026 marks an important step in enhancing the long-term value of Gran Tierra. I will now turn the call back to the operator, and Gary, Ryan, and I will be happy to take questions.

Operator, please go ahead.

Great, thank you. Thanks everyone.

Probably an obvious one to start, but maybe can you just talk about your exposure to near-term prices, please? Specifically, if you can just mention sort of how and when your sales are priced.

Secondly, a bit of a follow-on. I appreciate this is all new, but I see your CapEx guidance is the same in your base case and your high case, but that's up to $75.

I'm wondering, $80 plus, does that change? At what point does your thinking around capital allocation change?

A third one just on Azerbaijan, please, if you wouldn't mind just sort of giving us an idea on potential capital allocation there, please. Thank you.

Great. Thanks, David.

With respect to pricing, you're right, it is fairly new. The way our pricing works is we're paid in Colombia, we're paid just on the monthly average Brent price, and in Ecuador, we're paid at M minus 1, which is really the month of lifting, we get paid the prior month pricing, is how we get as far as the pricing.

In Canada, we're paid on the average of WTI for the month. Right now, and just for sensitivities, we do have a sensitivity in our corporate deck.

If you look at the low case, mid case, and high case, you're right that at the $75 high case, we're generating, it's about $130 million of free cash flow, and capital expenditures are relatively flat. They're actually the same across all categories.

I think right now it's too early to say what we do with the additional funds, but our capital program for 2026 is pretty well set. I think we would expect any material changes at all for 2026.

It really is help us with our planning for 2027. We're very focused on debt reduction, free cash flow generation, and so I think any excess free cash either go with cash on the balance sheet or repurchasing our outstanding debt.

Great. Then

with respect to Azerbaijan, we are still waiting to get the PSC ratified. Really, we'll come out with capital guidance for Azerbaijan, it's really a 2027 and beyond, with some capital this year, most likely some gravity that we'll shoot in Azerbaijan.

Makes sense. Maybe I can just sneak another quick one, just on OpEx.

It looks like actually a pretty meaningful reduction in OpEx in '26. How much of that is structural savings that we can assume will persist, and are there any deferrals we just need to be aware of there?

They're mostly all structural components. Even in Canada, we've reduced as a whole about 10% per year on a structural basis.

The integration of i3 has been significant, and the same goes in Colombia and in Ecuador. A lot of that is moving from our diesel to gas-to-power as we develop the field in Ecuador.

Brilliant. Thank you.

Morning, everyone, and thanks for taking my questions. First one for Ryan.

Ryan, with all these higher prices and you mentioned in your hedge book, how much incremental hedges have you put on and are you stretching that into '27? Is this war premium giving you the ability to add hedges at very attractive prices?

I think for this year, we have about 50% of our production hedged. We have started to add a few into Q1 of 2027.

I think the reality that obviously front month is quite a bit higher, but the curve is steeply backwardated. We are continuing to look at hedges for latter half of the year, but more so into next year.

As I said, we're about 50% hedged already this year. We may do some shorter-term options, take advantage of it, get above that 50%, probably through puts over the next couple months, but that really is about it.

Again, with the curve so steeply backwardated.

Okay. Next one, the disruption on the pipelines in the south for Colombia, and then the recent announcement of the Americans being involved with the Ecuadorian military, is there any concern about Ecuador production?

Has there been a recovery from the pipeline disruptions in southern Colombia?

Yeah. Thanks, Josef.

I think the answer that is there's no disruption in Ecuador. We're currently starting our water injection pilot test.

We are working with the government to tie into the OCP pipeline going forward. With the border disruption, the border being closed between Colombia and Ecuador, we have multiple ways to export our crude from Colombia, and so now it's all being exported directly from Colombia as opposed through the OTA and the SOTE lines.

No disruption to production or exports, it's just different routing.

Has production come up materially? What would production be now versus what it was during Q4?

In Ecuador, we're still at the 8,500, 8,500, 9,000 barrels a day, but we are quite quite enthusiastic. We're already seeing response from the injection in the fields that were on.

Our plans are to start water injection pilots in all of our fields.

Okay. In Colombia, production now versus Q4?

Josef, it's pretty much flat. As we manage the waterflood at Costayaco and Moqueta and we're doing some optimizations on both the waterflood and Moqueta is actually back up over 1,100 barrels a day.

We're essentially flat for Q4 to Q1 now.

Super. Thanks for answering my questions.

Hey, morning, guys. Thanks for taking my questions.

My first one just around the Simonette disposition in the context of your production guidance for this year. It sounds like operations are trending positively so far, but would you anticipate a small change to your production guidance range upon deal close or look to maintain your current guidance?

It it is we will revise our guidance once we've closed that transaction, which will happen here over the next week week or two going forward. It's it's it's not material, but it is an effective date of January 1st, 2026.

Great. Thanks, Gary.

Just one more for me, if I could. Can you just remind us of your activity in the Clearwater this year, and is there any potential to accelerate or expand the program there just following the Simonette disposition, the planned activity there?

Thanks.

Right now we're doing some more core work studies, essentially cost optimization studies for when we go to full-field development. To your point, we have an existing pad with room for up to 4 to 6 wells.

That's all in the planning stages that we can pull off of the shelf if we need to.

Great, thanks, guys.

Hi, how are you? You mentioned debt reduction, I was wondering what would be your target in terms of debt reduction and when do you think it's feasible to achieve that?

Thank you.

Longer term, we're targeting net debt to EBITDA of 1 times, and we're targeting that for 2028. Obviously, contingent on pricing, and pricing like today that accelerates quite quickly.

Great, thank you.

Thanks.

Hi, good morning. Just I guess a couple of follow-up questions on topics that have already been asked.

On the hedging program, you mentioned I think an average floor price of $60. Just what's the average ceiling price now that we have prices at least in the near term where they are?

I guess my first question.

About $74 is the ceiling.

Thank you. Then just following up on Alejandra's question, to the extent your focus now on free cash flow and debt reduction going forward, to the extent perhaps we'll have a little bit higher oil prices for longer, how do you think about, sort of, share buybacks versus net debt reduction or debt reduction, to the extent things end up better than your guidance, sort of how do you think of allocating between the two?

It's a good question. I think if you look at where the bonds yield right now, we're very focused on debt reduction, and our first choice would be to repurchase outstanding debt.

Then you'll recall in the exchange that we just did, any restricted payments that go out, we have to do 2-to-1 for debt reduction versus share buybacks. If we were to buy back $10 million worth of shares, we'd be obligated to buy back $20 million versus debt.

You can see the emphasis on the debt reduction.

Great. That's helpful.

Thank you.

You're welcome.

Thank you, operator. I'd once again like to thank everyone for joining us today.

I would like to also take this opportunity to thank the entire Gran Tierra team for their commitment and their hard work in 2025, while thanking stakeholders for their continued support. We look forward to speaking with you next quarter and update you on our ongoing progress.

Thank you.