Gran Tierra Energy - Earnings Call - Q4 2024

Executive Summary

• Record quarterly production of 41,009 boepd alongside $147.3M oil, natural gas and NGL sales; operating netback per boe fell to $22.19 due to lower Brent and a heavier Canadian natural gas mix.
• Adjusted EBITDA was $76.2M and funds flow from operations was $44.1M, both down sequentially vs Q3; management highlighted robust reserves and reiterated buybacks as a key return lever.
• 2025 production guidance maintained at 47,000–53,000 boepd; plan calls for 6–8 exploration wells (South America), 5–7 development wells (Suroriente), 2–3 appraisal wells (Ecuador), and 6 development wells (Canada).
• Note: Press materials contain a discrepancy on Q4 GAAP net income (narrative: +$34.2M vs table: –$34.2M and –$1.04 EPS); we flag for caution and reliance on reconciled tables and call commentary for analysis.

What Went Well and What Went Wrong

What Went Well

• Record quarterly production of 41,009 boepd and 2024 average WI production up 6% YoY to 34,710 boepd, supported by Ecuador exploration successes and two months of production from Canadian assets.
• Highest year-end reserves in company history and sixth consecutive year of 1P growth; before-tax NAV/share $35.23 (1P) and $71.14 (2P) underscore asset depth (“current share price trades at significant discounts”).
• Strategic capital returns: since 1/1/2022, 6.8M shares repurchased (~19% of shares outstanding) and NCIB renewed with ASPP to buy in blackout windows; management reiterated buybacks as the primary tool amid market volatility.
• CEO tone: “2025 is set to be a transformational year” with integrated Canada entry and 6–8 high-impact exploration wells; “repurchases remain a strategic and efficient way to return capital”.

What Went Wrong

• Operating netback per boe declined to $22.19 in Q4 (vs $34.18 in Q3 and $36.05 in Q4’23) on lower Brent and increased Canadian gas weighting; average realized price fell to $39.73/boe in Q4.
• Operating expenses rose YoY to $202.3M (8% increase) and per-boe operating costs edged higher; drivers included diesel subsidy removal and higher gas/electricity costs in Colombia, partially offset by Ecuador cost leverage.
• Suroriente blockades and Acordionero workover downtime impacted volumes intra-quarter; Q4 WI production surge masked pricing and netback headwinds.
• Financial disclosure inconsistency: press release narrative cites Q4 net income of +$34.2M, while the detailed table shows –$34.2M and –$1.04 EPS; we anchor on the tabular data and call commentary pending clarification.

Transcript

Operator (participant)

Good morning, ladies and gentlemen, and welcome to Gran Tierra Energy's conference call for the fourth quarter and year-ended 2024 results. My name is Shannon, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. Following the initial remarks, we will conduct a question-and-answer session for Securities Analysts and institutions. Instructions will be provided at that time for you to queue up for questions. I would like to remind everyone that this conference call is being webcast and recorded today, Monday, February 24th, 2025, at 11:00 A.M. Eastern Time. Today's discussion may include certain forward-looking information, oil and gas information, and non-GAAP financial measures. Please refer to the earnings and operational update press release we issued yesterday for important advisories and disclaimers with regard to this information and reconciliations of any non-GAAP measures discussed on today's call.

Finally, this earnings call is the property of Gran Tierra Energy. Any copying or rebroadcasting of this call is expressly forbidden without the written consent of Gran Tierra Energy. I will now turn the conference call over to Gary Guidry, President and Chief Executive Officer of Gran Tierra. Mr. Guidry, please go ahead.

Gary Guidry (President and CEO)

Thank you, Operator. Good morning and welcome to Gran Tierra's fourth quarter year-end 2024 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. This morning, we issued a press release that included detailed information about our fourth quarter and year-end 2024 results. In addition, Gran Tierra Energy's 2024 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 then we will open the line for questions. I'll now turn the call over to Ryan to discuss some of our financial results.

Ryan Ellson (EVP and CFO)

Good morning, everyone. We closed 2024 with record highs across all reserve categories and delivered our highest-ever quarterly production in Q4, setting a solid foundation for future growth. While 2024 was dedicated to investing and resource capture, 2025 and beyond will be focused on execution, in particular unlocking the full potential of our extensive oil-weighted portfolio, which holds over 293 million BOE of 2P reserves. We are also pleased to confirm that Gran Tierra successfully met its average production guidance target for 2024. In 2024, Gran Tierra demonstrated its confidence in the company's future prospects by repurchasing 6.7% of our outstanding shares through our normal course issuer bid program, showing our dedication to long-term shareholder value creation. Compared to our current 1P net asset value of $35.23 per share, repurchases remain a strategic and efficient way to return capital to our shareholders while reinforcing our commitment to long-term value creation.

In terms of production, Gran Tierra achieved 2024 average working-interest production of 34,710 BOE per day, representing a 6% increase from 2023. Due to positive exploration results in Ecuador and two months of production from our recently acquired Canadian operations, which was partially offset by lower production in the Acordionero field caused by downtime related to workovers and deferred production from blockades in Suroriente during the quarter. Building on the company's successful development drilling in 2024 and integrating our recently acquired Canadian assets, we expect 2025 production of 47,000-53,000 BOE per day. This projected 2025 production increase is expected to result from our 2025 development drilling program of five to seven gross wells in Suroriente, two to three appraisal wells in Ecuador, as well as six gross development wells in Canada.

Turning to exploration, we plan to allocate roughly 25% of our total capital program to exploration, which equates to six to eight exploration wells in 2025. With four of those wells being allocated to Ecuador, we expect to fully meet our Ecuador exploration commitments before the end of the year. Recall, when we entered Ecuador, we did not pay for the land, but rather committed to drilling 14 exploration wells. At the end of the year, that commitment is fulfilled, and we'll move to the development phase of the contracts. During 2024, Gran Tierra realized net income of $3 million or $0.010 per share, compared to a net loss of $6.3 million per share in 2023.

Gran Tierra's capital expenditures increased slightly by $7.7 million, or 3%, to $234 million compared to 2023, due to a higher number of wells drilled during the year, which was fully funded by the company's 2024 net cash provided by operating activities of $239 million. The company realized adjusted EBITDA of $367 million, a decrease of 8% from $399 million in 2023. 2024 funds from operations were $223 million, or $7.02 per share, compared to $277 million in 2023. Both of these decreases were commensurate with a decrease in the print prices. The company had $103 million in cash and cash equivalents as at December 31st, 2024, an increase compared to a cash balance of $62 million at the end of 2023.

Looking forward, Gran Tierra is targeting $600 million gross debt by the end of 2026 and $500 million by the end of 2027, resulting in a target net debt EBITDA of less than one times. We recently paid the remaining 2025 bonds outstanding and plan to pay the 2026 amortization through cash on hand and available credit facilities. Gran Tierra's net oil sales for the year were $622 million, a slight decrease of 2% compared to 2023. Total 2024 operating costs were $202 million, compared to $187 million in 2023, representing an 8% increase, while operating expenses per BOE were $16.14, 2% higher when compared to 2023. The increase in 2024 was primarily as a result of higher workovers, removal of diesel subsidies in Colombia, and higher natural gas and electricity costs in 2024.

Despite higher operating expenses in 2024, Gran Tierra effectively managed inflationary pressures, showing the resilience in cost control and maintenance activities. I'll now turn the call over to Sebastien Morin to discuss some of the highlights of our current operations.

Sebastien Morin (COO)

Thanks, Ryan. Good morning, everyone. I'll briefly cover a few operational highlights from the press release, as well as discuss the highlights from our 2024 year-end reserves. Operationally, we are building off a successful year in 2024 to start off 2025 on a strong note. As Ryan mentioned, 2024 was focused on resource capture, and 2025 and beyond will be focused on production growth while paying off debt. The capital program and its allocation have been formulated with that in mind. We are excited to have commenced drilling in Colombia at the Suroriente Block, with the first well on the Cohembi North pad spudding on February 10th. Production is expected by the end of the first quarter of 2025. In Ecuador, we are currently drilling the first exploration well of our six to eight well program with the Iguana SUR-B1 exploration well, which spud on February 4th.

In Canada, the development plan with our new joint venture partner, Logan Energy, has commenced with the first two horizontal wells being drilled at Simonette. Both wells are currently being stimulated and expected to be on stream by the end of the first half of 2025. In Q4 of 2024, we drilled five new wells in the Clearwater at East Dawson and Walrus, which has confirmed the quality of our acreage in the Clearwater play. All of the wells are now on stream and cleaning up. In addition, we are currently participating in a waterflood pilot at Marten Hills with the drilling of a four-leg multilateral injector, which spud on February 13th and is expected to be online in the first half of 2025.

Moving on to our year-end reserves, on January 23rd, 2025, we were pleased to release our 2024 year-end reserve report as evaluated by McDaniel. 2024 saw the highest year-end reserves in our company's history: 167 million barrel oil equivalent 1P, 293 million barrel oil equivalent 2P, and 385 million barrel oil equivalent 3P. We achieved excellent reserves replacement results of 702% for 1P, 1,250% for 2P, and 1,500% for 3P. This also represented the sixth consecutive year that we achieved 1P reserve growth. These results are underpinned by multiple exploration discoveries in Ecuador, continued success in managing our low-decline Colombian assets, and our new country entry into Canada. The organic and inorganic portfolio growth creates a future runway of highly economic development opportunities and proven plays with access to infrastructure.

Furthermore, with the addition of Canada, Gran Tierra is well-positioned for long-term commodity cycles, with approximately 20% of its production, 23% 1P reserves, and 26% 2P reserves now attributed to natural gas. Canada now represents 46% of 1P and 51% of 2P reserves compared to Gran Tierra's total reserves. We also achieved a year-end 2024 NAV per share of $35.23 before tax and $19.51 after tax 1P, and $71.14 before tax and $41.03 after tax of 2P. Looking at where Gran Tierra's current share price trades, this is a significant discount across all of the company's NAVs per share categories and why we are focused on share buybacks as a key pillar of shareholder returns. Looking at additional maintenance costs, including change in future development costs for 2024 on a barrel oil equivalent basis, Gran Tierra came in at $0.74, $8.11, $6.18 and 3P.

Looking at final development, there was changes in came in at $4.44, $2.10, and 3P on a barrel oil equivalent basis. These metrics show that the company's relative cost when it comes to adding barrels to the portfolio. To close, I would like to point out that with a robust and diverse portfolio of assets, with 227 1P and 441 2P identified undeveloped well locations, Gran Tierra is poised to capitalize on emerging opportunities and deliver value to all our stakeholders. As we continue to profitably advance our operational and financial goals, we remain deeply committed to the well-being of our employees and the communities where we operate, recognizing their essential role in our success. We are looking forward to 2025 and how it sets Gran Tierra up for success for years to come.

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.

Operator (participant)

Thank you. Ladies and gentlemen, we will now conduct the question and answer session for securities analysts. If you have a question, please press the star key followed by one one on your touch-tone phone. You will then hear an automated message advising your hand is raised. Your questions will be polled in the order they are received. Please ensure you lift the handset if you're using a speakerphone before pressing any keys. One moment, please, for your first question. Our first question comes from the line of Anne Milne with Bank of America. Your line is now open.

Anne Milne (Managing Director)

Hi, good morning, Gary, Ryan, everyone else in the team. Thank you for the call. I have three very different questions. The first one has to do with your higher cost of sales in 2024. Maybe you could give us an idea of going forward if you think that will go back down to previous levels in 2025 and also incorporating, I guess, the Ecuadorian and the Canadian cost as well. That's the first question. Second question is, if you were to look forward, including these assets for 2026 and 2027, where do you think you might see production at that point in time? Obviously, your reserve levels are really strong, and you do have a development program, but just looking forward a little bit more.

The third question is, I think I've asked you this before, but maybe you could just remind me, the sale of production from all three of your regions, but more from Canada. I think most of it is domestic, but maybe you could say about that which is not domestic, where it goes. Same question on Ecuador and Colombia, obviously having in the back of my mind impact of potentially higher tariffs. Thank you.

Ryan Ellson (EVP and CFO)

Hey, Anne, thanks for the questions. Yeah, with respect to the higher costs in 2024, would you expect those to trend down in 2025? We got hit with a number of things in 2024. Part of it was the removal of the diesel subsidies in Colombia, but also just the increase of natural gas. We're a buyer of natural gas to generate power. There were just higher electricity costs in general just across the country. That impacted. We also have about 75% of our costs are fixed. As we ramp up production, especially in Ecuador, these are all satellite fields right now.

We don't have a ton of wells drilled in Ecuador, but as we move to more permanent facilities and we're starting to generate gas power in Ecuador as well, we would expect those units to actually come down, the unit costs in Ecuador to come down, and really to probably lead the pack as far as lower operating costs. We do expect that to decrease in 2025 and into 2026 as well. Looking out to 2026, we have guidance this year for 47,000-53,000 barrels. We're quite comfortable that we can grow 5%-10% with this asset base. A lot of that depends on capital allocation, of course. We try to get the right balance between reinvestment in the portfolio and portfolio longevity, but also having that production growth. As you point out, we have $293 million BOE of 2P reserves.

I think that's a great proxy for the resource potential in the company and production profile growth in the company. Again, with 25% of that being natural gas, a lot will just depend on natural gas prices, which obviously we expect to increase in 2026 and beyond. With respect to where we sell our production, in Canada, we sell most of our production domestically. I think what's happened, if you look at the tariff talk, obviously there's tariff talk in Colombia as well as in Canada. We're quite well insulated. If you look at what happened to all of our oil in Canada, it is light oil, which is consumed domestically. A lot of it is diluent. If you look at what happened to heavy oil or light oil spreads in Canada, they widen by about $1 with the tariff talks.

If you look at what's happened in South America, differentials have tightened by $3. Vasconia has gone from $5-$2 right now. We produce 10 times the amount more production in South America than in Canada. The diversification does help us, and we'd actually be a net benefitor of tariffs to the extent that they do come in.

Anne Milne (Managing Director)

Okay. The higher, let's say, price because of the lower differentials would more than offset the potential tariff increase.

Ryan Ellson (EVP and CFO)

Exactly. Exactly. Also in Canada, we expect if tariffs were to come in, WTI should widen a little bit, increase, which would offset some of that. We think it would be quite negatively impacted on the Canadian dollar, which you've already seen. The dollar is at $0.70 right now. We get paid in Canadian dollars and our costs here are in Canadian dollars.

Anne Milne (Managing Director)

Okay. Where do you sell in Canada the natural gas?

Ryan Ellson (EVP and CFO)

Natural gas, we sell domestically, and we sell it to BP.

Anne Milne (Managing Director)

Okay. If you were to take it all together, you expect minimal impact from tariffs if they were to be implemented.

Ryan Ellson (EVP and CFO)

Correct. To be honest, we think a net positive to the company.

Anne Milne (Managing Director)

Okay. Thanks very much.

Ryan Ellson (EVP and CFO)

Not good for the country, but positive for Gran Tierra.

Operator (participant)

Thank you. Our next question comes from the line of Harrison Lock with Stifel. Your line is now open.

Harrison Lock (Associate Equity Research Analyst)

Hi. Thank you for taking my question today. Just a couple from me. Firstly, I'm interested in the capital structure and looking forward ahead of this year. Can we expect any changes here? Secondly, how has the integration gone with the i3 Asset package? Has there been any surprises here for you guys? Do you see any scope for realizing synergies over time with this? Appreciate it's a different asset base, but with the corporate stuff, if we can have some color around that, please.

Ryan Ellson (EVP and CFO)

Yeah. I'll take the first question. Gary will take the second question. Yeah. When you look at our current capital structure, if you look in 2026, we have $186 million maturing. We expect to fund that through cash on hand and maybe some of our available credit facilities if required. Keeping the enterprise value constant, we should see that value move over to equity holders. We would think, and that's what we're targeting, reducing our total net debt as well. We are focused on that, and we think we have a great free cash flow in business to make those changes organically just through free cash flow.

Gary Guidry (President and CEO)

On integration with i3, we're very pleased that essentially all of the team came across from i3. We completely integrated, not just a Canadian asset team, integrated throughout the company. The benefit of that, that really we see is a very large benefit, is technology transfer, taking things that are happening in the Western Canadian Sedimentary Basin to Colombia, to Ecuador, and vice versa, being able to bring some of our team that are operating in Colombia and Ecuador to Canada for that training. We see it as a huge benefit and a step forward for the company. The integration has gone quite well.

Harrison Lock (Associate Equity Research Analyst)

Okay. Fantastic, guys. That's all from myself. Thank you very much.

Gary Guidry (President and CEO)

Thank you.

Operator (participant)

Our next question comes from the line of Alejandra Andrade with J.P. Morgan. Your line is now open.

Alejandra Andrade (Latam Corporate Research)

Hi. Good morning. Thanks for taking my question. I just had two questions. First, I wanted to ask if we were to separate kind of the Colombia business versus the others, if you could talk a little bit about discounts in Colombia specifically. Also, I know you've discussed in the past the possibility of additional committed lines. I just wanted to see kind of where were you in that process of negotiating an additional line. Thanks.

Ryan Ellson (EVP and CFO)

Yeah. Thanks for the questions. Yeah. With Colombia, the Vasconia discount last year was around $5. It's narrowed to $2. And Castilla has gone from $8-$9 to $5-$6. We've seen a significant tightening of those discounts. Not to talk of tariff talks, a result of tariff talks on Canada and Mexico, but also just a drop in production from Mexico as well. You've really seen some of the heavier crudes tighten up. In Colombia, as you know, there are lots of ways to get your barrels to tide water. It's a natural counterparty to make up for some of the shortfall seen globally on the heavies. As far as line, yeah, we're still working on that. We obviously have an undrawn facility in Canada for $50 million.

That's really capped at our choice just to minimize our standby costs. The borrowing base is quite a bit higher. Potential borrowing base is quite a bit higher. We are still looking at adding on a working line for Colombia. We expect to have that closed this quarter or early next.

Operator (participant)

Great. Thank you so much.

Gary Guidry (President and CEO)

Thank you.

Operator (participant)

Our next question comes from the line of Rob Mann with RBC Capital Markets. Your line is now open.

Rob Mann (Equity Research Analyst)

Hey, good morning, team. Thanks for taking my questions. Just two quick ones for me here. The first being, is there any additional information on the Iguana SUR exploration well that you can share at this time? Secondly, although natural gas is a relatively small portion of your portfolio, I know you touched on it a bit there, Ryan, but just curious if you could give us your expectations for the impact of LNG Canada phase one coming online this year. That's all for me. Thanks.

Sebastien Morin (COO)

Great, Rob. I'll take the first one on Iguana. We've got the well cased, and we're just into completion program now. In the next coming weeks, testing will be coming next.

Ryan Ellson (EVP and CFO)

With respect to natural gas, yeah, this year, we still think natural gas to be fairly choppy. When we purchased i3, it was taking a long-term view on natural gas. I think the budget that we're using for this year is CAD 2.50 of AECO pricing. We do have a fairly large hedge position, so we're hedged over that level. Longer term, we're very bullish on natural gas. Short term, we expect 2025 to be a little choppy. As you point out, Shell LNG will obviously have a huge impact, taking about 10% of the domestic production to the export markets.

Rob Mann (Equity Research Analyst)

That's great. Thank you.

Operator (participant)

Thank you. Our next question comes from the line of Joseph Schachter with SER. Your line is now open.

Josef Schachter (Energy Analyst)

Good morning, Gary, Ryan, and Sebastien. First question for Ryan. Thank you for the guidance on the net debt goal, net debt of $600 million at the end of 2025. If there is free cash flow above that, if prices improve, what is the goal to knock down debt faster or narrow the discount given the cheapness on the NAV? Do you see more NCIB or more debt or kind of a balance between the two?

Ryan Ellson (EVP and CFO)

Yeah. That's a great question. Yeah. A balance between the two. Yeah. We plan to put 50% of our free cash flow, additional free cash flow to debt reduction and 50% to share repurchases.

Josef Schachter (Energy Analyst)

Okay. One for Gary. I gather there's an election in Ecuador coming up. Are we looking at issues there between right and left and politics impacting the oil patch, or is it a central government that will continue along the same way, which has worked out well for you in terms of building the business there?

Gary Guidry (President and CEO)

Yeah. I think the first round just occurred a couple of weeks ago. President Noboa did better than expected in the first round, achieved a higher percentage of the vote. It is going to the second round, and we fully expect him to win the election going forward. Continue with the conservative approach, business-friendly approach in the country.

Josef Schachter (Energy Analyst)

Okay. Good. A question for Sebastien. In the supporting material for the annual report, you break down the reserves there by country. And at the end of 2023, just under $70 million for Colombia, technical revisions, production, number 63 point, well, I'll say $64 million at the end of the year. Is the program that you have this year able to stabilize that, or should we be modeling in declines there, but increases in Ecuador and Canada?

Sebastien Morin (COO)

No, I think you should be able to model that and maintain essentially because we've got our whole reserve replacement plan outlined for the year. I feel quite comfortable with maintaining that.

Josef Schachter (Energy Analyst)

Okay. Last one, again, this one for Gary. The market's not being very nice today to the stock. Any thoughts there of things that can be done, sell non-core assets? The stock was down below $7, $7.39 now. Any thoughts there on market reaction and what you can do to get more shareholder support?

Gary Guidry (President and CEO)

Yeah. I think the one Ryan just mentioned, we're going to continue buying back our stock, trading at a significant discount to PDP going forward. We always look at non-core assets to, number one, shore up the balance sheet, but also consolidate in some other areas in Western Canada. We're doing quite well with the drill bits in Colombia and Ecuador, and we'll continue that going forward. I think the answer to your question is the only primary tool in our toolbox here is to continue to buy back shares.

Josef Schachter (Energy Analyst)

Okay. Thanks for the answer. Thanks very much, guys. Have a good day.

Operator (participant)

Thank you. Gentlemen, there are no further questions at this time. Please continue.

Gary Guidry (President and CEO)

I would like to once again thank everyone for joining us today. I'd like to also take this opportunity to thank the Gran Tierra team for the commitment and all of the hard work during 2024, and thank our shareholders for their continued support. We look forward to speaking with you in the next quarter and updating you on our ongoing process. Thank you.

Operator (participant)

This concludes today's conference call. Thank you for your participation. You may now disconnect.