EGY

Good day, welcome to VAALCO Energy's first quarter of 2026 earnings conference call. All participants will be in a listen-only mode for the duration of the call. Should you need any assistance today, please signal a conference specialist by pressing the star key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then 1 on your telephone keypad. To withdraw a question, please press star then 2. Also, please be aware that today's call is being recorded. I would now like to turn the call over to Investor Relations Coordinator, Chris DeLange. Please go ahead.

Thank you, operator. Welcome to VAALCO Energy's first quarter 2026 conference call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the first quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. During our question and answer session, we ask you to limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. I would like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparisons, and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements.

Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website, and in the reports we file with the SEC, including our Form 10-K. Please note that this conference call is being recorded. Let me turn the call over to George.

Thank you, Chris. Good morning, everyone, and welcome to our first quarter 2026 earnings conference call. Over the past two years, we have streamlined and expanded our portfolio while delivering consistently solid operational results. In February 2026, we divested all of our Canadian assets and simultaneously added to our Côte d'Ivoire position by being named operator with a 60% working interest in the Kossipo field on CI-40 block. We are actively evaluating and processing seismic with our partners in Niosi Marin and Guduma Marin Blocks offshore Gabon and on our exploration block CI 705 in Côte d'Ivoire. At Etame, we have had several successful wells drilled, and the rig has now moved to Ebouri to drill the next well in our drilling campaign.

The Baobab FPSO has successfully completed its refurbishment and is now moored back into position with wells being reconnected and production expected to resume in early June. We discuss our operational and financial results today, it is important to remember that 2025 was a transitional year for VAALCO as production came offline in Q1 at Côte d'Ivoire due to the FPSO project, and we did not start the drilling campaign in Gabon until late Q4. First quarter 2026 was a pivotal quarter operationally. We are beginning to see the significant production uplift we are projecting from these major projects in Q2 2026 and expect it to continue into 2027. We are confident in our ability to execute and have increased our full year 2026 production, sales guidance, and added to our work program without increasing our capital expenditure guidance.

I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets beginning with Côte d'Ivoire. I would like to remind you that we had no assets in Côte d'Ivoire prior to April 2024. Since that time, we have developed a significant production and prospective portfolio. In line with the project timeline, the FPSO at Baobab ceased hydrocarbon operations in January 2025. Following a year of refurbishment in Dubai, the FPSO returned to Côte d'Ivoire in April and is now moored into position, and we have four out of the seven risers and umbilicals connected. We expect the field to restart production in June, with sales commencing from the FPSO in Q3. We are very pleased how well the FPSO refurbishment went and that it was completed within the initial timeline expected.

The refurbishment was undertaken to extend the life of the vessel and to increase its capacity as we begin a significant development program at Baobab later this year. The program includes 4 producers, 2 or 3 water injectors, and 2 workovers, providing potential meaningful additions to production from the main Baobab field, where we have a 10-year extension of the license to 2038. The current drilling plan on Baobab is to begin drilling on a batch basis the top hole sections of all wells. These completions will then be commenced, and we expect at least 1 well to be on full production by year-end. In February 2026, in accordance with the CI-40 PSC, VAALCO and Petroci elected to participate in the development of the Kossipo field.

VAALCO was confirmed as operator with a 60% working interest in the Kossipo field on the CI-40 block, just 8 kilometers from the Baobab field. We are now working on a field development plan using new ocean bottom node seismic data that is expected to help de-risk and enhance our evaluation and development plan. The Kossipo field was discovered in 2002 with the Kossipo-1X well and later appraised in 2019 with the Kossipo-2A well, which tested at over 7,000 barrels of oil per day. Our current assessment has the field with an estimated gross 2C resources of approximately 102 million barrels of oil equivalent and 293 million barrels of oil equivalent in place.

In Côte d'Ivoire, we continue to evaluate the subsurface potential of our new exploration block, CI-705, which we operate with a 70% working interest. We continue to see encouraging prospectivity on the block in proven play types through the Ivorian Basin, including both structural and stratigraphic traps in the Upper Cretaceous and Albian sections. We have met all current work commitments on the block and have been granted a 6-month extension to the first exploration phase, which now extends this phase into Q4 2026. Our subsurface work will continue to mature the encouraging prospectivity we see on the block in preparation for a decision later this year to proceed to the 2 exploration phase, which carries a well commitment. In less than 2 years, we have established a sizable position in Côte d'Ivoire with considerable upside potential.

We are generally excited about the prospectivity in Côte d'Ivoire and their ability to help us achieve our production growth targets. Moving to Gabon, in the fourth quarter of 2025, we began our phase three drilling program with the drilling of two pilot wells in the Etame field. Based on the pilot well results, we proceeded with the drilling of Etame 15H development well on the 1V block of Etame in December 2025. This well came online in late February at about 2,000 gross barrels of oil per day, so our Q1 production results only had one month of production from this well. The rig remained on the Etame platform to drill an exploration prospect in West Etame. While this well encountered 10 meters of high-quality Gamba sands, the target zone was water-bearing and not commercial.

The lower portion of the well was plugged and abandoned, but the wellbore was utilized as sidetracked in the upper portion of the well to drill the Etame 14H development well in the main fault block of Etame that was de-risked from the results of the earlier pilot wells. In late April, the Etame 14H was brought online with an impressive initial rate of around 4,850 gross barrels of oil per day. This well encountered 325 meters of lateral net pay in high-quality Gamba sands in an attic position within the main fault block at Etame. Our second quarter production at Gabon should be enhanced by two months of production from this very successful well.

After completing a program at the Etame platform, we moved the rig to the Ebouri platform where we are drilling a development well and a workover well to enhance production, lower costs, and potentially add reserves. We also plan another two wells at SEENT platform following the completion of the program at Ebouri. We expect that development well at Ebouri to be completed later this quarter, and we plan to announce the results to the market when that happens. Regarding our exploration blocks in Gabon, the Niosi Marin and Guduma Marin, we are working with our partners on plans for the two blocks moving forward. We commenced a seismic survey in November of 2025, which was completed in the first quarter of 2026. This survey completed part of the exploration work program commitment for these blocks.

Processing of the seismic data has begun with early products expected to begin arriving later this year. Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks. Turning to Egypt, for the past year, we had contracted a rig and drilled about 20 wells across a drilling campaign that helped to increase production year-over-year in 2025. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. In conjunction with our drilling program, we also continued to perform production optimizations, workovers, and recompletions that have significantly improved our production performance.

While we wrapped up the drilling program in the fourth quarter of 2025, given the strong results, we have added a 6-well drilling program in Egypt that is commencing in Q2 and which should help increase production in Q3. We have not increased our CapEx guidance for 2026 for the cost of these wells as the range we provided in March can comfortably include these new wells. We also plan to optimizations, workovers, and recompletions in 2026 that are focused on production enhancement. Egypt production remains strong, and we continue to invest to drill development wells and continue to delineate opportunities in Gazala that could open additional prospects in the future. Turning to Equatorial Guinea, in March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development.

Last summer, we began our front-end engineering design, or FEED study. The FEED is complete and confirms the technical viability of our plan of development. Also highlights some of the risks and challenges from the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development versus the original shelf development, which would also significantly simplify the drilling operations and well design. This evaluation is currently underway. We are expecting to proceed with our plans to develop, operate, and begin producing from the discovery in Block P offshore. We are targeting Venus FID in 2026. In closing, we have an outstanding diversified portfolio of assets that we believe have significant upside opportunities. We remain focused on growing production, reserves, and value for our shareholders. I'd like to thank our hardworking team who continue to operate and execute our plans.

Over the past several years, we have significantly diversified our portfolio, enhanced our capacity to generate operational cash flow while returning capital to shareholders, and increasing our credit facility capacity. We are well-positioned to execute the projects in our enhanced portfolio, and our proven track record of success these past few years should instill confidence for our future. With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George. Good morning, everyone. I will provide some insight into the drivers for our financial results with a focus on the key points and give additional insight into our 2026 guidance. As George discussed, operationally, we are performing very well. The first quarter was an inflection point for us financially. I want to begin by highlighting the multiple factors that impacted our Q1 financial results, including the timing and number of liftings in Gabon, exploration expense, and both realized and unrealized derivative losses. I want to point out that in the previous conference call and in our Q1 guidance, we discussed the reduced sales volumes expected in Gabon due to the sole lift being a government lift.

As I've previously stated, in Gabon, Egypt, and Côte d'Ivoire, our foreign income taxes are settled by the government through oil liftings in Gabon and Côte d'Ivoire and the government taking their share in Egypt. We also sold the Canadian assets in February and as a result, only had a portion of production and sales from those assets in Q1. Additionally, as George discussed, Côte d'Ivoire remained offline for the FPSO refurbishment and production should resume by the end of the second quarter. Despite all these factors, our Q1 sales and production were both slightly above the midpoint of our guidance. We forecasted that Q1 sales would be quite a bit below production, but the midpoint of the full-year production and sales guidance are much more in line, which means sales will likely exceed production in future quarters. This can be seen in our Q2 guidance.

While Q1 sales had no partner liftings in Gabon, we expect two partner liftings in Q2, which is expected to significantly increase our sales, revenue, and ultimately our Adjusted EBITDAX. Another major factor impacting earnings and the expenses in the first quarter was the $22.4 million in exploration expense. This was driven by the cost of an exploration well at West Etame offshore Gabon that was determined to be unsuccessful and additional seismic costs at the Niosi and Guduma blocks in Gabon. In the previous call, we also discussed the forecasted exploration expense, Q1 actually came in below the guidance range of $27 million-$32 million. Nearly all of our expected annual exploration expense came in in Q1. Turning to hedging.

In the first quarter of 2025, we entered into a new reserve-based lending facility to help provide VAALCO with the short-term funding to supplement our internal cash flow generation as we have multiple large capital projects underway across our portfolio. Over the past year, we've been talking about a more programmatic hedging program that will be more consistent over a rolling time horizon. We are looking to mitigate risk and protect the cash flow needed for our capital investments and shareholder distributions through the ongoing hedging program. Prior to the Iran conflict, the hedging program, consisting primarily of collars, allowed us to protect our downside risk and lock in a range of prices that allowed us to generate strong cash flow.

As you know, the market has been very volatile since March, and our hedges had about $15 million in realized losses in the first quarter, with an additional $56 million in unrealized derivative losses as we mark-to-market the positions. We had 56% of our guided Q1 barrels hedged with costless collars, the unhedged positions being largely represented by the Egyptian sales, where the PSC terms provide the state with 85% of the pricing upside over cost oil and the contractor 15%. We are continuing to monitor the situation and hedge on any geopolitical shock or spike where we can. With Côte d'Ivoire coming back online, we will have more oil barrel sales unhedged in Q3 and beyond. Our full quarterly hedge positions are disclosed in the earnings release. Turning now to the first quarter results.

We reported a net loss of $93.7 million in Q1 2026, which was driven by $71 million in derivative losses, of which $56 million represents unrealized book losses and a $22.4 million exploration expense. While most of our expected exploration expense for 2026 occurred in Q1, with the uncertainty in macro events and oil pricing, our realized and unrealized derivative losses could continue to impact earnings in the coming quarters. We also generated Adjusted EBITDAX of $11.6 million, which included no partner liftings in Gabon and no sales in Côte d'Ivoire. Q2 2026 is expected to be materially improved due to the two planned partner liftings in Gabon and a Q3 2026 sales is expected to include Côte d'Ivoire.

With the FPSO expected to be fully operational in June, we are forecasting some production in Côte d'Ivoire in Q2, but there won't be any liftings until Q3. Production in Q1 was 15,110 NRI barrels of equivalent per day or 19,884 working interest BOEPD, both above the midpoint of VAALCO's guidance. As I discussed earlier, sales of 12,157 NRI BOEPD for Q1 were slightly above the midpoint of guidance, but quite a bit lower than production. Turning to costs. With no partner liftings in Gabon, our production costs for Q1 on an absolute basis were quite a bit lower than in Q4 2025, and were well below the midpoint of guidance, both on an absolute basis and on a per barrel basis.

Our focus remains on keeping our costs low to enable us to maximize margins and increase cash flow. With higher fuel and service costs driven by the Iran conflict, we may see some expenses increase in the near term. Looking at G&A, our cash G&A totaled $6.9 million, which was below the low end of guidance. Moving to taxes. In the first quarter, we reported an income tax expense of $4.3 million, which was comprised of a $14.9 million current tax expense, offset by deferred tax benefit of $10.6 million. Income tax expense included a $2.9 million unfavorable oil price adjustment as a result of the change in value of the government's allocation of profit oil between the time it was produced and its present mark-to-market liability.

Turning now to the balance sheet and cash flow statement. In Q1, we invested $78.1 million on a cash basis and $73.3 million on an accrual basis in net capital expenditures. This was primarily related to new wells drilled as part of the drilling campaign in offshore Gabon, as well as expenditures associated with the refurbishment and reconnection activities of the FPSO in Côte d'Ivoire. Keep in mind, we wrote off the cost of the unsuccessful West Etame well, so that cost is not in CapEx. Unrestricted cash at the end of the first quarter was $48 million. In the first quarter, to help fund our capital programs, we did draw $92 million against the company's reserve-based lending facility. In April, the aggregate borrowing base under the 2025 RBL facility increased to $300 million.

We now have $152 million drawn on the credit facility and net debt of $104 million. We anticipate a substantial part of the interest we incur this year from the facility borrowings will be capitalized and is in our capital guidance. Last call, I discussed how pleased we were in 2025 the progress made with our Egyptian receivables, and I said that we expected to see collections to exceed revenue in Q1 2026. For the first quarter, we saw an additional reduction to our trade receivables of about $7.4 million, with our trade receivables falling from just under $32 million at year-end 2025 to just over $24 million at the end of the first quarter, 2026.

We will continue to work with the Egyptian General Petroleum Corporation to maintain this strong relationship and keep our receivables current. In Q1, 2026, VAALCO paid another quarterly cash dividend of six and a quarter cents per common share or $6.7 million. We also announced the second quarter dividend payment, which will be paid in June. Let me now turn to guidance, where I'll give you some key highlights and updates. As I mentioned earlier, guidance for the remainder of 2026 has no contribution from the Canadian assets that were sold in February, and we are forecasting the Baobab field in Côte d'Ivoire coming back online in June with sales resuming in Q3.

With the strong performance of our drilling campaign, coupled with the restart of production at Baobab and some additional drilling in Egypt, we expect to see strong increases in production from Q1 levels moving forward. With two partner liftings in Gabon expected in Q2, our sales guidance is 44% higher in Q2 at the midpoint compared to Q1 sales. We are confident in our operational abilities and are increasing our full year 2026 production and sales NRI volumes by 8% and 12% respectively. Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with production breakout of both working interest and net revenue interest by asset area.

For the total company, we are forecasting Q2 2026 production to be between 21,600 and 23,800 working interest BOEPD and between 16,800 and 18,700 NRI BOEPD. This is a significant increase over Q1 production. We expect our second quarter 2026 NRI sales volumes to range between 16,800 and 18,300 BOE. We expect our absolute production cost to be higher in the second quarter, in line with the additional sales volume and on a per BOE expense to be in the range of $26-$31 per NRI BOE. This is slightly higher than Q1, as we are expecting some cost increases primarily related to fuel costs and reflects a higher mix of West African barrels versus North African barrels that dominated the mix in Q1.

For our exploration expense, we are forecasting a range of between $2 million and $3 million for Q2 and 90% reduction compared to the first quarter. We expect cash G&A to be in the range of $7 million to $9 million and our annual G&A guidance remains the same. Finally, looking at CapEx, our Q1 spend was below the guidance range, but we believe this is primarily due to the timing. Our Q2 2026 capital spend is projected to be between $110 million and $130 million as we continue the drilling campaign in Gabon, we complete the FPSO refurbishment and begin drilling additional wells in Egypt. George outlined the multiple programs across our assets as we believe that our efforts in 2025 and 2026 are building the foundation for another step change in production in the future.

Our second quarter guidance includes about $6 million in capitalized interest, all of which relates to our large capital investment program this year. Even though we are adding a drilling rig in Egypt and increasing our 2026 production and sales volumes, our full year capital guidance for 2026 remains unchanged. In closing, while Q1 results were impacted by several factors, we are optimistic about improvement in Q2 and for the remainder of 2026 as we expect to continue to grow production and sales volumes. We believe we remain well positioned to continue executing on our strategy of growing production and reserves while adding meaningful value. We have a long track record of successfully delivering operational results that meet or exceed expectations. We've achieved many things these past few years, and 2026 has started with strong operational successes.

We've delivered in the past. We're very well positioned to continue to execute at a high level across our diversified assets over the next several years. With that, I'll now turn the call back over to George.

Thanks, Ron. Our second quarter is off to a strong start with the drilling success at Gabon and the FPSO at Côte d'Ivoire back on location with production expected to restart at Baobab in June. In the first quarter, we rationalized our portfolio by selling the Canadian operations and added high upside opportunities at Kossipo in Côte d'Ivoire. Looking across our asset base, we are executing on several projects across our expanded portfolio. In Gabon, we have an extensive drilling campaign underway, and the rig is now in Ebouri drilling wells and looking to do workover that should add reserves and production.

At Baobab, a couple of months after the field comes back online, we are expecting to begin a multi-well development drilling program. At Kossipo, we are very excited to be named operator with a 60% working interest and are working on a field development plan that is being driven by new seismic, and we are looking to utilize existing infrastructure already in place. Also in Côte d'Ivoire, we are acquiring additional regional well data, licensing seismic data, and concluding further geological evaluations of our new exploration block CI-705, where we're the operator with a 70% working interest. In Egypt, our ongoing production optimization, workover, and recompletion programs has performed well, and we are drilling additional wells in 2026, as I discussed earlier.

In Equatorial Guinea, we have completed our initial front-end engineering and design study and confirmed the viability of the development concept and are currently evaluating alternative technical solutions which may deliver enhanced economic value. Our ability to remain focused on successfully executing our strategy is key to growing the company profitably over the remainder of the decade. We have successfully delivered strong operational and financial results for the past several years, where we have met or exceeded guidance on a quarterly basis.

We believe that we can continue to meet or exceed our guidance numbers in Q2 and beyond. There are numerous macro events that we cannot control, but the things that we can control, like operating efficiently, investing prudently, and maximizing our production, will help us deliver the forecasted growth and profitability for our shareholders and partners. The timing of the new wells in our Gabon program recently coming online and the expected restart of Côte d'Ivoire later this quarter are certainly very well timed with the increase we're seeing in oil prices. Our entire organization is actively working to deliver strong results that will continue to help fund our capital programs, while also returning value to our shareholders through a top-quartile dividend.

We have maintained credibility over the past several years, having delivered on our commitments to the market and to our shareholders. We will continue to deliver with these exciting slate of projects we have over the next few years. We are in an enviable position with a much stronger and diverse portfolio of producing assets with expected significant future upside potential. Thank you. With that operator, we are ready to take questions.

Our first question here will come from Stephane Foucaud with Auctus Advisors. Please go ahead.

Yes. Morning or afternoon, gents. Thanks for taking my question. My question is really around realization. We are hearing those wide premium in the market versus Brent. I heard recently that some lifting in Nigeria were sold at a 15 premium, dollar premium to dated Brent, which is already at a premium on the M plus 1 prices. I was wondering, is it what you see across your portfolio in Gabon and Egypt? Related to that, some of the production you have is hedged, but I assume that this hedging is around Brent, so that still allows you to capture, even on that hedged production, any potential premium. If you could confirm if my understanding is right. Thank you.

Hi, Stephane, it's Ron. Yes, you are correct. I mean, obviously we saw at times a difference between the screen price and what we saw in dated Brent. We had two listings that are coming up. I can talk to them, April and May. In both occasions we're seeing about a $4 premium to dated Brent for our crude. Yes, we are seeing a premium for African oil at this point in time. Egypt's a more difficult one because it's domestically sold, but obviously the listed price in relation to that we're marked off of from EGPC is getting closer to obviously dated Brent. Not necessarily seeing the premium develop there per se, but we've certainly seen it on the West African barrels.

It's obviously far too soon on CI-40. We won't have a lift in CI-40 until about April, sorry, August.

Thank you. With regards to the, hedging?

With regards to the hedging, can you repeat what that question was again?

Well, my question was that I assume the hedging are financial hedging, which is basically they are based on Brent.

Yeah.

Any premium you still capture.

Yeah, we do because it is on dated Brent. You're quite right. Any premium to that will be above what we've got our hedges in place at.

Okay, that's great. Thank you very much.

No problem.

Our next question will come from Jeff Robertson with Water Tower Research. Please go ahead.

Thank you. Good morning. Ron, can you share any additional color on the lifting schedules in Gabon and Côte d'Ivoire beyond the second quarter?

We can certainly share in the second quarter we've got 2 confirmed listings in Gabon. We're working with a partner in CNR for Baobab, but we'll likely see a listing there in August time period. We basically have stated that we'll have 1 every other month in Gabon between now and the end of the year. As we stated previously, there's not gonna be another or we don't foresee another GOC lift this year. It's all contractor party lifts. Hopefully that helps you with your modeling there.

George, at Kossipo, if you get the field development plan submitted before year-end, what will that do to VAALCO's ability to shift reserves from one category to another?

Yeah, I mean, if we get the FDP in place before year-end, which is our commitment to the DGH in Côte d'Ivoire, basically these categorizations of the 102 million barrel equivalent is currently sitting in 2C. That would put it to a 2P categorization within our NSAI report for year-end. That's definitely our focus. That would add on to our 2P reserve books somewhere in the region of just north of 60 million barrels.

Thank you.

Our next question will come from Charlie Sharp with Canaccord. Please go ahead.

Yeah, thanks for taking my question. Just another bit of a follow-up, if I may, on listings. That's been very helpful in terms of the timing of those listings. I guess, can you remind me what the typical listing size is in Gabon? Or what the anticipated typical listing size would be on Baobab? Also just on your production guidance for Côte d'Ivoire, are you, does your guidance capture any potential flush production, or would that be potentially on top of guidance? Thank you.

I'll start with the listings then, Charlie. Typically we, in the past, in Gabon, we've lifted sort of parcel sizes of 650 gross. As of late, we've tried to maximize that out to 900,000. That, you know, obviously from an economics point of view and the freight makes it more beneficial for us. We're planning 900,000 gross lifts. In CDI, we generally plan 650 lifts, but we are working with the operator there to try and encourage higher lifts than that. Obviously, the vessels come back. It is in very good shape. There's no Certainly in my mind, there's no reason why we can't be looking at sort of 900,000 to 950,000 lifts.

I'll add to what Ron said there. Charlie, one of the reasons we were with the operator down at 600 is, you know, their initial plan when the vessel came back on stream was not to use the wing tanks. That plan has subsequently been changed, and we're just finalizing some remedial work on site on the wing tanks right now to make sure we have that additional storage. That means that where before we had perhaps used those partly for ballast, they now can be used for storage capacity. That starts to increase the argument around the higher listings from Baobab. With regard to the guidance, of course, we work closely with the operator when it comes down to the production forecast.

We have our own simulation models that we work on the Baobab field and where we see the performance. You're absolutely correct that with a field shut-in for some 14 months, we would expect to see flush production. We haven't put all the anticipated flush production upside into our guidance. There's really 2 reasons for that. One, you know, we are confident in the history match in our model that we have, that what we're seeing indicatively of a kickstart in production will be achieved. We'll hold that in reserve right now. The second reason is, unlike, for instance, Etame, there's not a natural pressure support inside the Baobab field that requires water injection in order to sweep that oil up to the drainage points.

The water injection has also been, as you're aware, shut down during this period. On the startup sequence, we would expect the water injection to begin, and we do expect to see flush production, but we've kept that in reserve at the moment.

Okay. Very helpful all around. Thank you.

Our next question will come from Chris Wheaton with Stifel. Please go ahead.

Thanks very much. Two questions if I may for, guys. Firstly, Ron, a question for you on working capital, if I may. I was surprised at the magnitude of the working capital outflow in first quarter, particularly when my reading of the accounts is that and you look at the difference between sales and production volumes, that the Gabon cargo wasn't Sorry, the Gabon cargo for, to pay the government taxes was already taken out of the revenue line. I wonder if you could help unpick that there for me, because it feels like I've double-counted somewhere, or there's been double counting somewhere of both the Gabon tax revenue and also working capital outflow. My second question was for George on Kossipo. It's fantastic to see that head towards FID.

Is the development plan presumably monetization via some of the Baobab infrastructure? In that case, has a sort of commercial framework been agreed with CNRL as operator so that that can form part of the sort of the financial framework that goes into assessing the project viability? Those are my two questions. Thank you.

Thanks, Chris. It's Ron. I'll go first on working capital. On working capital in relation to the tax position. Obviously, when we accrue up the barrels, they're on the balance sheet as a liability for foreign taxes payable, Chris. When we settle those, effectively you're moving the working capital 'cause there's an outflow of cash as you take those barrels off and settle them against that liability. That did happen in Q1. Also our accounts payable came down a bit as we settled, as along with CNR, a number of the bills on MV-10 when it came out of sailed out of Dubai and came back into the African water. There was a movement in payables there as those bills were settled.

We completed a well in Gabon as well. Obviously, you've got the payments going out for that, for bore drilling too. Those were the kind of key catalysts. The other part is there is an inventory build as you go to the latter half of the quarter. The GOC lifted that early February and the partner lift was in April. Again, inventory built up a little bit. With the strong prices AR built up, although we collected most of the AR. Overall, that's where the outflow came. Against that, obviously the unrealized hedges now has moved up the accrued liability number.

I'll take the question on Kossipo, Chris. Maybe it's maybe not well-known, but even though we are the operator now of Kossipo in that economic extraction area, we're still under the single PSC. Within that PSC, any of the developments that are attached to CI-40 has a contractual right to evacuate back through the existing infrastructure. That is very much clearly there. With regard to the economics for, you know, coming through processing and storing through Baobab, that still has to be worked out, but it's worth pointing out as well that we are also, you know, 30% participants in that position and have a voice at that table on both sides, effectively.

That all being said, when we're looking at the FDP, we've got to look at what is the most efficient extraction. We were 8 clicks away from Baobab, so either an interconnect or tieback solution. How does that look both from a capital spend and an engineering concept. There's also the opportunity to look at a standalone position if that is more economically efficient and more importantly, can be done in a more timely manner. I think all the listeners should take comfort that we have absolute contractual rights to evacuate through Baobab and maximize the efficiency of that facility if the timing allows.

That's a really helpful explanation there, George. Thanks very much indeed. Thank you.

Thanks, Chris.

Our next question will come from Bill Dezellem with Crichton Capital. Please go ahead.

Thank you. Two questions related to production. First of all, production in the first quarter was quite good relative to your guidance that you gave. Ultimately, what went right for that to come in so strong relative to guidance?

Okay, there's two things there. One, as we mentioned, I guess back in March, we intimated that the upward trajectory on production coming out of the Egyptian campaign in December meant we had a very strong profile coming into January and February. That was a big delta in our production upside. It also, because of the performance, particularly around the final wells in the Egyptian campaign, really led towards the acceleration of the campaign for 2026, pulling it forward from effectively a late Q3, Q4 prospectivity that we had kind of in a contingent to a firm program coming into May.

That really, that really changed our position on pulling forward the activity in Egypt because of the strong performance that came through in December and into first and second quarters. In addition to that, we did see obviously a little bit of a kick coming from the performance in Gabon. It continued to be more or less just above guidance from the wells. We obviously had the 2 new wells coming on in the drilling campaign. Primarily the kick against our forecast was coming in from Egypt. Yeah.

Okay. Thank you. Then relative to the 14H well, the upper part of that well that came in at really a quite high production rate, does the knowledge of that level of production lead to some learnings or a change in how you are thinking about future drilling in that area?

Yes and no is the answer to that. I think it's worth reminding everyone, you know, we've been drilling and producing out of Etame for some 24 years now. It's a very mature field. When we talk about, in the announcements we talk about and the targeted drilling that we're going for, we talk about the concept of going after attic oil. What that actually means is we're looking at the positions where the existing drainage points are down dipped of the upward parts of the structure, and we're trying to place these wells at the very top part of the structure to capture that additional oil that hasn't been swept by previous wells.

You're correct in your assessment there that a well design is always looking to come across with an extended lateral at the very top of the structure to gather that attic oil that's never going to be swept from the existing draining points. It's exactly the same type of well that we're trying to drill right now in Ebouri with exactly the same type of concept. All future wells, I believe in Etame will be this type of well design. Top of the structure, very long lateral, very long exposure to the reservoir in order to capture those stranded oil opportunities.

Bill, I'll just add a little bit more color to what George said there. I mean, as you saw, we increased the production and sales guidance from our Q4 call. That's primarily with a view on that main fault block well, which came in very well, as well as the, you know, continued Egyptian success that we've got. That's where the rise in the production and sales is on the full year guidance.

Great. Thank you both, and good luck with finishing the FPSO hookup.

Thanks, Bill.

Good.

If you have a question or follow-up, you may press star then 1 to join the queue. Our next question is a follow-up from Stephane Foucaud with Auctus Advisors. Please go ahead.

Yeah, thank you. Actually, Bill asked the question I wanted to ask, and I could not contemplate. That was around what had driven the production guidance increase in 2026 in Gabon. I think Ron just responded to that, saying that this was basically the very strong well in Q1. Thank you.

Our next question is a follow-up from Jeff Robertson with Water Tower Research. Please go ahead.

Thank you. Thank you. George, at Niosi and also at your two blocks in Gabon, what's the earliest you might expect to see wells drilled there if you continue down that path?

Okay. On these blocks, if you recall, when we acquired these along with BW Energy and Panoro, the commitment position on these blocks was basically seismic acquisition, processing, interpretation, and one, a single well commitment. Had we been a little bit ahead of the game, we could have thought of tagging on that single well commitment at the end of this campaign in Gabon. We're definitely not gonna be there because the acquisition obviously just completed in mid-January, and it's out for interpretation, processing and interpretation. We're not even expecting hot shot data probably into Q3, maybe as late as Q4 for the evaluation. As I think has been announced by BW Energy, they've picked up a rate to commence a program in later this year in Gabon.

That program for them, I believe, runs through mid end 27. There's an opportunity that commitment well, subject to interpretation and identification of a targeted location, could come in late 27, early 28 at the back end of that program. Failing that, it's then gonna be down to looking at the next opportunity for a rig to be in the area to meet that commitment on the drilling program.

At Niosi, if you move to the second exploration phase, which I think will begin, I guess at the end of this year, I think you have that might include a well by 2028. Would that likely be a 2028 well or could that slip into 2027?

It's unlikely to slip into 27. It depends on 2 key things. 1, the location of the well. I firmly believe because you've got to look backwards into VAALCO's history, and you look backwards, and these blocks that have been reassigned to us and our partners are areas that VAALCO previously held back in the early teens. We do have an understanding of the prospectivity of that block, and that's why we were quite comfortable to come back in in a partnership because we do see a degree of prospectivity there. Now, as to when and where that well will ultimately be drilled is down to 1, the location of the well and its proximity to infrastructure.

The closer to our infrastructure or their infrastructure, obviously it makes it more exciting for us to pull that forward because it's a much closer monetization point. That's really what's gonna be the driver is how exciting is the prospects that we find and the location of these prospects to existing infrastructure. The closer they are, the more keen we would be to drill them. It's unlikely in my mind, but it's never, you never say never, that it would be falling into 2027. There is that slight possibility.

Thank you.

Our next question will come from Jamie Whalen with Whalen Management. Please go ahead.

Hey, fellas. You guys have a lot of moving parts which I'd like to tie together. As you exit 2026, will your barrels per day production approach 30,000 barrels?

Jamie, it's Ron. Our guidance at the moment has an exit rate of between 25,000 and 27,000 barrels. Obviously we'll continue to look at that with the Gabon drilling successes as we go forward. Obviously CDI, we've previously stated we go into a batch drilling there, and we only see one of those wells completing. That will be very late on in the year, so it will come in for 1 month. If there's movement there's a possibility for that exit rate to be higher than that. At this point in time, we're guiding an exit rate of between 25 and 27.

The only thing I'd add to that, Jamie, is as I said earlier in the call, you know, there's all kinds of possibilities of flush production coming on CDI when we start up. That's currently not within our guidance.

Okay. Secondly, as far as taxes go, in 2026 and 2027, we have a lot of cost oil that will go to limit our tax liability. How much free cash flow will we have that will not be taxable as we look forward?

I can't give you specifics on free cash flow. It's not taxable. What I can say to you, to Jamie, is if, and you know, you've been in this role for some considerable time, so you know the history here. In relation to the cost pools building up, we basically see for Gabon, as I say, there will be no other GOC state list this year. I can't see a state list now, and my team can't see a state list now on the volume metrics until Q1.

2027. Again, there's not a, you know, cash tax liability in relation to that. We also foresee with the spend that we've got both for the Baobab Ivory and for the drilling campaign in CDI. We think that will maximize that cost pool for about a 2-year period. It really depends on oil price. If oil prices stay, you know, at this current level of $100, you know, you will burn through those cost pools quicker. That's the same case with Gabon. You know, it's great that we will have incremental free cash flow from that, from the pricing. It'll also mean it will burn through it. We won't have that tax expense.

What you'll do is you'll crystallize that benefits to the company quicker than our models predict at the moment, which, you know, our models have forward curve in there.

Not a bad thing at all. Thanks, fellas.

Thank you.

Thank you.

This concludes our question and answer session. I'd like to turn the conference back over to George Maxwell for any closing remarks.

Thank you, operator. I'd just like to thank everyone for participating in today's call. Obviously, we've had a considerable amount of activity, and I think as Jamie mentioned in his last question, we've got a lot of moving parts. We've got a lot of catalysts that are happening throughout 2026. By the time we get to midyear, we'll have 3 drilling campaigns fully active in our assets, producing wells. Sorry, drilling wells and enhancing production. Again, catalysts to generating cash flow. We've got a very, very busy year ahead, and that busy year is building both the profiles and the opportunity for significant steps ups in production in early 2027.

I don't want to look that far ahead because we only need to look as far ahead as Q2 when we start to see, you know, the increase in the crude oil sales coming from liftings, and that liftings are increasing even more with the additional production that we're taking in Gabon from the drilling campaign and the restart of the Baobab field. We've seen Egypt operating very successfully from the last campaign in Q4 2025. We made that decision to accelerate the program in 2026 to further enhance those opportunities. As you can see, that, and then we've got our developing assets in Kossipo. We didn't talk much about Equatorial Guinea, but I'll just highlight again, we're going to FID for Equatorial Guinea this year.

We're building the portfolio to continue that step change in production going into 2027 and 2028. With that, I'd like to thank everyone for participating. I look forward to talking to you in the Q2 call in August. Thank you.

Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.

Good morning, and welcome to the VAALCO Energy Fourth Quarter and Full Year 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Al Petrie, Investor Relations Coordinator. Please go ahead.

Thank you, operator, and welcome to VAALCO Energy's Fourth Quarter and Full Year 2025 Conference Call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the fourth quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. [Operator Instructions] I'd like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparison and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements within the meaning of federal securities laws. As a reminder, these statements are based upon our current beliefs, as well as certain assumptions and information currently available to us as we discuss in more detail in our fourth quarter and year-end 2025 earnings release and our Form 10-K for the year ended 2025 we expect to file on and before March 16, 2026. Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website and the reports we file with the SEC, including our Form 10-K. We will also refer to certain non-GAAP financial measures, including adjusted EBITDAX, whose reconciliation you will find in the fourth quarter and year-end 2025 earnings release and in our slide deck. Please note that this conference call is being recorded, and let me turn the call over to George.

Thank you, Al. Good morning, everyone, and welcome to our fourth quarter and full year 2025 earnings conference call. Over the past 3 years, we have delivered outstanding operational and financial results, including generating over $750 million in adjusted EBITDAX while meeting or exceeding our quarterly guidance targets. Maintaining operational excellence and consistent production across our portfolio is essential to increasing our adjusted EBITDAX, which has allowed us to expand our portfolio and also to fund organic growth initiatives, better positioning VAALCO for the future. We recently divested all of our Canadian assets, and we added to our Cote d'Ivoire position by being named operator with a 60% working interest in the Kossipo field on Block CI-40. Last year, we added an exploration block, CI-705, in Cote d'Ivoire and are working with our partners on the seismic acquisition and processing at Niosi Marin and Guduma Marin blocks offshore Gabon. In addition, we drilled our first exploration well in Gabon since 2013 during Q1 2026. And although unsuccessful, combined with the new exploration portfolio in Gabon and CDI, we have created a more balanced portfolio between production, development and high-quality prospective assets. We have accomplished many things in these past 5 years, growing VAALCO from a single asset delivering around 5,000 barrels a day to a diversified multi-country operator, well on our way to achieving our goal of 50,000 barrels of oil equivalent per day. We have, over the past several years, in addition to growing production, reserves and adjusted EBITDAX, has been a sustained commitment to returning cash to shareholders. In 2025, we returned another $26.5 million in dividends. And since Q4 2021, we have returned over $115 million to our shareholders through dividends and share buybacks. As we discuss our operational and financial results today, it is important to remember that 2025 was a transitional year for VAALCO as production came offline in Q1 at Cote d'Ivoire due to the FPSO project, and we did not start the drilling campaign in Gabon until late Q4. This means that the meaningful production uplift we are projecting from these major projects won't begin until later this year and into 2027. I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d'Ivoire. I'd like to remind you that we had no production or interest in Cote d'Ivoire prior to April 2024, when we made the Svenska acquisition, securing a valuable asset with Baobab on the CI-40 block. In line with the project time line, the FPSO at Baobab ceased hydrocarbon operations as scheduled on January 31, 2025, with the final lifting of crude from the vessel occurring in early February. The vessel departed from the field in late March and arrived in the shipyard in Dubai ahead of schedule in mid-May 2025. The FPSO refurbishment went very well, and the FPSO departed Dubai in early February 2026 on route back to Cote d'Ivoire. The vessel is currently off the coast of South Africa and continues to be on track to return to Baobab, with the field restarting in Q2 2026. Significant development drilling is expected to begin later this year after the FPSO returns to service with a drilling program which includes 3 producers, 2 to 3 injectors and 2 workovers providing potential meaningful additions to production from the main Baobab field, where we have a 10-year extension to the license to 2038. The current drilling plan on Baobab is to begin drilling on a batch basis, the top hole sections of all 5 wells. The completions will then be commenced, and we expect at least 1 well to be on full production by year-end. In March 2025, we announced a farm-in agreement for the CI -705 block offshore Cote d'Ivoire, where we will operate with a 70% working interest and a 100% paying interest through the seismic reprocessing and interpretation stages and potentially drilling up to 2 exploration wells. The block is favorably located in a proven hydrocarbon system and is approximately 70 kilometers to the west of our CI-40 block, which contains 1.2 billion barrels of oil equivalent of [ stope ]. We received seismic data for the block, and we are conducting a detailed integrated geological analysis to assess and mature our understanding of the block's overall prospectivity, as well as the basin's overall potential. In accordance with the CI-40 PSC, VAALCO and PetroCI elected a sole risk development of the Kossipo field. In February 2026, VAALCO was confirmed as operator with a 60% working interest in the Kossipo field on the CI-40 block, just 8 kilometers from Baobab field. We are now working on a field development plan using new ocean bottom node seismic data that is expected to help derisk and enhance our evaluation and development plan. The Kossipo field was discovered in 2002 with the Kossipo-1X well and later appraised in 2019 with the Kossipo-2A well, which tested at over 7,000 barrels of oil per day. Our current assessment has a field with an estimated gross 2C resources of approximately 102 million barrels of oil equivalent and 293 million of barrel of oil equivalent in place. So in less than 2 years, we have established a sizable position in Cote d'Ivoire with considerable upside potential to help us achieve our production growth targets in a significant and high-demand hydrocarbon basin. We have demonstrated our ability to acquire, develop and enhance value through accretive acquisitions, and we are excited about the prospects in Cote d'Ivoire. Moving to Gabon. Given that we haven't drilled a well in Gabon in over 3 years, we are pleased with the overall positive production results we saw in 2025. In July 2025, we successfully completed a planned full field maintenance shutdown of the Gabon platforms to perform safety inspections and necessary maintenance. This is the first time that we have had to perform a full field shutdown at Gabon since the FSO was brought online in 2022. In the fourth quarter of 2025, we began our Phase 3 drilling program in Gabon with the drilling of 2 pilot wells in the Etame field. Based on the pilot well results, we proceeded with the drilling of the Etame 15H-ST development well on the 1V block of Etame in December 2025. The rig remained on the Etame platform to drill an exploration prospect in West Etame. While the well encountered 10 meters of high-quality Gamba sands, the target zone was water-bearing and noncommercial. The lower portion of the well will be plugged and abandoned, but the wellbore will be utilized and sidetracked in the upper portion of the well to drill the ET-14H development well in the main fault block of Etame that was derisked from the results of the earlier pilot wells. When we committed to drilling the Etame West exploration well, we knew there was geological risk of not encountering commercial sands, but the size of the potential resource made it a risk worth taking. Furthermore, we purposely designed the well so we could still utilize the wellbore to drill a development well into a nonproductive area if the sands were noncommercial. We are now working to drill the sidetrack well, which should be completed in April. After completing our program at the Etame platform, we expect to move the drill rig to the SEENT and Ebouri platforms, where we have several wells and workovers planned to enhance production, lower costs and potentially add reserves. Regarding our exploration blocks in Gabon, the Niosi Marin and Guduma Marin, we are working with our partners and the operator on plans for the 2 blocks moving forward. We commenced a seismic survey in November of 2025, which was completed in the first quarter of 2026. This survey completed part of the exploration work program commitment for these blocks. Further evaluation and interpretation of the results are expected to continue into the second and third quarters of 2026. Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks. Turning to Egypt. For the past year, we had contracted a rig and drilled 20 wells across a drilling campaign that helped to increase production year-over-year in 2025. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. We have been able to drill 8 extra wells faster and cheaper than what we had budgeted for the same amount of capital, which has also positively impacted production. In conjunction with our drilling program, we also continue to perform production optimizations, workovers and recompletions that have significantly improved our production performance. While we wrapped up the drilling program in the fourth quarter of 2025, the very good results drilled at the end of the year have resulted in Q1 2026 producing consistently above 11,000 barrels of oil per day and well above our budget of 10,700 barrels of oil per day. We plan to continue optimizations, workovers and recompletions in 2026, focused on production enhancement, while we finalize our development and exploration opportunities for the upcoming drilling campaign. In the Western Desert, work is ongoing to evaluate and integrate the results of our last exploration well in South Ghazalat. This well has confirmed the presence of both oil and gas. The long-term test and pressure monitoring that we have carried out has confirmed the connection of the oil-bearing zone to a larger volume. Based on this, we are updating our subsurface mapping, prospective evaluation and volume estimation in order to put together the appropriate economic field development plan for our acreage. We are particularly pleased with the progress our team made in our Egyptian receivables in 2025. Ron will discuss this in more detail, but we are now essentially on a current billing basis with EGPC. On February 5, 2026, we announced an agreement for the sale of all of our Canadian assets to a third party for approximately $25.5 million, which equates to 2.7x our trailing 12 months operational cash flow. The Canadian properties were producing approximately 1,850 barrels of oil per day at the time of sale, and the sale closed in February 2026 as expected. As Ron reviews our production guidance for 2026, keep in mind that our first quarter and full year 2026 results will only include January and a prorated February through the 19th Canadian production and financial results. We believe we have extracted significant value from the Canadian assets, including almost $65 million in operating cash flow since their acquisition. While we believe the Canadian assets are solid, we decided to focus on our core assets and their significant upside potential. With all of the large-scale drilling campaigns underway or planned in those areas, we determined that now was the right time to sell. Turning to Equatorial Guinea. In March 2024, we announced the finalization documents of the Equatorial Guinea related to the Venus Block P plan of development. Last summer, we began our front-end engineering design or FEED study. The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risks and challenges on the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development versus the original shelf development, which would also significantly simplify the drilling operations and well design, and this evaluation is currently underway. We're excited to proceed with our plans to develop, operate and begin producing from the discovery in Block P offshore Equatorial Guinea in the next few years. Before I turn the call over to Ron, I would like to highlight some positives with our 2025 year-end reserve results. Our SEC reserves were prepared by NSAI, an independent third-party engineering firm that has provided annual independent estimates of VAALCO's year-end SEC reserves for over 16 years. While SEC proved reserves at year-end decreased modestly year-over-year by 5% to 43 million barrels of oil equivalent, we did see 4 million barrels of oil equivalent of positive revisions, additions and extensions, which replaced 2/3 of our 2025 production of 6 million barrels of oil equivalent. Also, with the Phase 3 drilling program in Gabon starting near the end of 2025 and the FPSO returning and drilling at Baobab starting in 2026, we expect to see more additions and extensions related to our organic drilling program in 2026 and 2027. Additionally, despite lower average SEC pricing of around $70 per barrel, our SEC proved reserve PV-10 increased 8% from $379 million to $410 million due to positive revisions, offset by widening differentials in Gabon and a decrease in year-over-year SEC prices. Year-end 2025 SEC reserves included a 17.5 million barrel of oil equivalent in proved developed reserves and 25.5 million barrels of oil equivalent in proved undeveloped reserves. Turning to our 2P CPR estimate, which includes proven and probable reserves. Using VAALCO's management's assumptions for future pricing and costs reported on a working interest basis prior to deduction of government royalties, we also saw a small year-over-year decrease of 6% to 73.7 million barrels of oil equivalent. Despite this, the 2P CPR and PV-10 saw a 26% increase to $859 million at year-end 2025. We have a strong runway of opportunities that will continue to add value. And as you can see from our SEC proved reserves, 2P CPR reserves and corresponding PV-10 values compared to our current market cap, our stock price remains undervalued. In closing, we have an outstanding diversified portfolio of assets that have significant upside opportunities. We remain focused on growing production, reserves and value for our shareholders. I'd like to thank our hard-working team who continue to operate and execute our plans. Over the past several years, we have significantly diversified our portfolio, enhancing our capacity to generate operational cash flow and adjusted EBITDAX while returning capital to shareholders and increasing our credit facility capacity. We are well positioned to execute the projects in our enhanced portfolio, and our proven track record of success these past few years should instill confidence for our future. With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George, and good morning, everyone. I will provide some insight into the drivers for our financial results with a focus on the key points and give additional insight into our 2026 Q1 and full year guidance. Let me first echo George's comments about our continued success and our ongoing ability to meet or exceed our quarterly and annual sales, production and cost guidance, leading to consistent operational and financial results. I want to remind you that in 2025, at midyear, we increased the midpoint of our full year production and sales guidance. Even with these higher targets, we were able to deliver 17,452 net revenue interest barrels of oil equivalent per day of sales in 2025, above the high end of our increased guidance. We also delivered production of 16,556 net revenue interest barrel of oil equivalent per day or 21,160 working interest barrels of oil equivalent per day, both above the midpoint of VAALCO's increased guidance. These strong sales numbers helped us generate adjusted EBITDAX of $173.4 million and net cash from operating activities of $212.7 million for the full year of 2025. In the fourth quarter, we reported a net loss of $58.6 million or $0.56 per diluted share, which was driven primarily by a noncash impairment charge of $67.2 million due to the sale of our Canadian assets. This impacted our full year net income, as well as pushing it into a net loss. After generating $17.2 million of net income in the first 9 months of 2025, we ended the year with a net loss of $41.4 million, driven by the fourth quarter and the noncash impairment charge. Turning to costs. Our production costs for 2025 were in line with guidance, both on an absolute basis and on a per barrel basis. With the lower sales in 2025, we were down on an absolute basis, but slightly higher on a per barrel basis year-over-year. For the full year 2025, absolute expense was $158 million and on a per barrel basis was $24.89. For the full year 2024, while the absolute costs were up by about $10 million, our per barrel costs were slightly lower at $22.48. Cash G&A costs were below the low end of guidance for the fourth quarter and for the full year 2025. Our focus remains on keeping our costs low to enable us to maximize margins and increase our cash flow. Exploration expense for the fourth quarter was $6 million, and was primarily attributable to the purchase of 3D seismic costs associated with Niosi and Guduma blocks in Gabon, as well as costs associated with an Egyptian exploration well in South Ghazalat determined to be currently not commercially viable. The well confirmed the presence of hydrocarbons, and the team are updating their mapping, prospect evaluation and volume estimation in order to put together the appropriate economic field development plan to present to both our partner and the state. Moving to taxes. In the fourth quarter, we reported an income tax benefit of $4.6 million, which was comprised of a $5.2 million current tax expense, offset by a deferred tax benefit of $9.8 million. Income tax benefit includes a $7.3 million favorable oil price adjustment as a result of the change in the value of the government of Gabon's allocation of profit oil between the time it was produced and the time it was taken in kind. For the full year 2025, income tax expense was $14.8 million, which included a deferred tax benefit of $29.4 million. As I've previously stated, in Gabon, Egypt and Cote d'Ivoire, our foreign income taxes are settled by the government through oil liftings in Gabon and Cote d'Ivoire and the government taking their share in Egypt. Turning now to the balance sheet and our cash flow statement. Unrestricted cash at the end of the fourth quarter increased by nearly $35 million to $58.9 million at December 31, 2025 while continuing to fund VAALCO's capital program with no draws against the company's RBL in the fourth quarter. We are particularly pleased with the progress our team have made in our Egyptian receivables in 2025. Collections from the Egyptian General Petroleum Corporation accelerated in 2025, and all of our aged receivables are now current. At the start of 2025, our outstanding accounts receivable for EGPC amounted to $113 million. And at year-end 2025, this balance had fallen to $31 million, even after invoicing over $129 million in revenue for the year. We collected over $210 million in 2025, boosted by an industry payment of $40 million received in the last week of the year. Additionally, we continue to see collections exceeding revenue through quarter 1 of 2026 In 2025, we entered into a new reserves-based lending facility with an initial commitment of $190 million and the ability to grow to $300 million. The facility has a current commitment level of $255 million and only $60 million drawn at year-end 2025. This facility is helping to supplement our internally generated cash flow and cash balance to fund our active capital programs in Gabon and Cote d'Ivoire. As expected, during the first quarter of 2026, we expect to make additional draws against our RBL for our 2026 capital program. We anticipate a substantial part of the interest we incur this year will be capitalized and have been taken into our capital guidance. In Q4 2025, VAALCO paid a quarterly cash dividend of $0.0625 per common share or $6.5 million. And in 2025, we returned $26.5 million to shareholders through dividends. We also announced the first dividend payment of 2026, which will be paid later this month. Turning to hedging. Earlier this year, prior to the Iran conflict, we saw opportunities to get better pricing for our hedging portfolio and took advantage of the market at that time. We were able to secure collars that have a floor of about $65 per barrel for the balance of 2026 for about 50% of our production with ceilings as high as the market allowed when the hedges were put in place. The market is very volatile right now, but we will continue to monitor the situation and hedge on any geopolitical shock or spike where we can. Our full quarterly hedge positions are disclosed in the earnings release. Let me now turn to guidance, where I'll give you some key highlights and updates. I want to remind you that guidance for 2026 has the Canadian assets for only a portion of the first quarter, with the sale closing in the middle of February, and we are forecasting the Baobab field in Cote d'Ivoire coming back online in Q2. So there are some ups and downs in production and sales for the first half of 2026, but we expect both to increase materially in the second half of 2026 when the FPSO is back online and the full impact of the Gabon drilling campaign is realized. Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with our production breakout of both working interest and net revenue interest by asset area. For the total company, we are forecasting Q1 2026 production to be between 18,700 and 20,600 working interest barrels of oil equivalent per day and between 14,200 and 16,000 net revenue interest barrels of oil equivalent per day. This takes into account the Canadian asset sale, the continued FPSO project and natural decline. We expect our first quarter 2026 net revenue interest sales volumes to range between 11,200 and 12,900 barrels of oil equivalent per day. For the full year 2026, we are forecasting a production range for the total company to be between 20,100 and 22,400 working interest barrels of oil equivalent per day and between 16,100 and 17,950 net revenue interest barrels of oil equivalent per day. Our expected full year 2026 net revenue interest sales volumes are 14,900 to 18,050 barrels of oil equivalent per day. For the first quarter, we are forecasting our sales to be lower than our production, driven by a single state lifting in Gabon. With a substantial capital and operational program in 2026 for Gabon, we forecast this state lift should be the only state lifting in 2026. We are projecting 5 optimized liftings in the year, with the timing of 1 every other month beginning with April. We expect our absolute operating cost to be in line with 2025. And with our sales also in line with 2025, we are projecting our 2026 per barrel of oil expense to be in the range of $23.50 and $31 per net revenue interest barrels of oil equivalent. We are also expecting slightly higher absolute cash G&A in 2026. For our exploration expense, taking into account the seismic work in Gabon and Cote d'Ivoire, along with the West Etame exploration well, we are forecasting exploration expense to be between $30 million and $35 million for 2026, with a midpoint of approximately $29 million for the first quarter, when we expect most of the expense to occur. Finally, looking at CapEx. Our 2026 capital spend is projected to be between $290 million and $360 million as we continue the drilling campaign in Gabon, complete the FPSO refurbishment and begin drilling at the Baobab field in Cote d'Ivoire, continue recompletions in Egypt and begin spending in Kossipo. George outlined the multiple programs across our assets, as we believe that our efforts in 2025 and 2026 are building the foundation for another step change in production in the future. For the first quarter, we are expecting a range of between $90 million and $110 million for our CapEx. Our first quarter guidance includes about $3 million in capitalized interest, while the full year 2026 includes about $22 million to $24 million in capitalized interest, all of which relates to our large capital investment program this year. In closing, we are well positioned to continue executing our strategy of growing production and reserves while adding meaningful value. We have a long track record of successfully delivering results that meet or exceed expectations. We've achieved many things these past few years, and 2026 looks like it will be another strong operational and financial year. Despite all of this, we continue to trade at a low multiple of EBITDAX. And with a robust organic capital program of high-return growth opportunities, we are forecasting substantial increases in sales and adjusted EBITDAX in the future. We've delivered and very well positioned to continue to execute at a high level across our diversified assets over the next several years. With that, I'll now turn the call back over to George.

Thanks, Ron. As you have heard this morning, we have successfully delivered strong operational and financial results for the past several years by successfully executing on our diversification and growth strategy. In these past 5 years, we have achieved so many milestones that reflect the efforts and hard work of our employees in making the company that you see today. We have successfully grown VAALCO from a single asset delivering around 5,000 barrels of oil per day to a diversified multi-country operator, well on our way to achieving our goal of 50,000 barrels of oil equivalent per day. Our strategy remains unchanged. Operate efficiently, invest prudently, maximize our asset base and look for accretive opportunities. This continues to deliver for our shareholders, partners and all stakeholders in VAALCO Energy. We have rationalized our portfolio, adding high upside opportunities at good prices, and we are poised to deliver meaningful organic growth in the future. Looking across our asset base, we have a multitude of projects to execute. In Gabon, we have an extensive drilling campaign underway at Etame that should add reserves and production. The FPSO at Baobab is nearly back in Cote d'Ivoire, and the field is expected to be back online in the next couple of months as we work with the operator on the 5-well development drilling program that is scheduled to begin later this year. At Kossipo, we are very excited to be named operator with a 60% working interest, and we are working on a field development plan that is being driven by new seismic, and we're looking to utilize existing infrastructure already in place. Also in Cote d'Ivoire, we're acquiring additional regional well data, licensing seismic data and conducting further geological evaluations to our new exploration block, CI-705, where we are the operator with a 70% working interest. In Egypt, we have an ongoing production optimization workover and recompletion program, and we're examining drilling additional wells. In Equatorial Guinea, we have completed the initial front-end engineering and design study that confirmed the viability of the development concept and are currently evaluating alternative technical solutions which may deliver enhanced economic value. Our entire organization is actively working to deliver sustainable growth and strong results to continue funding our capital programs while also returning value to our shareholders through our top quartile dividend. I believe we have gained credibility over the past 3 years, having delivered on our commitments to the market and to our shareholders, and we will continue to deliver with the exciting slate of projects we have over the next few years. We are in an enviable financial position with a much stronger and diverse portfolio of producing assets with significant future upside potential. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserves and cash flow has not been fully reflected in our stock price, but we believe we will see the market begin to properly value VAALCO as we execute on our organic opportunities over the next few years. Thank you. And with that, operator, we're ready to take questions.

[Operator Instructions] Our first question today is from Stephane Foucaud with Auctus Advisors.

So I've got a question around CapEx in Cote d'Ivoire. And perhaps if you could provide a bit more granularity on how it is split? In other words, what's FPSO, what's drilling, what's maybe Kossipo? And more importantly, how much CapEx you would expect or residual CapEx you would expect in '27 for this drilling program that you would start in '26 in Cote d'Ivoire? And then I would have a follow-up on Kossipo.

Thank you, Stephane. Well, obviously, the guidance we've been giving for Q1 in relating to the CapEx, the majority of that is split between the drilling program in Gabon and the hookup for the FPSO in Cote d'Ivoire. So at that point, we expect around about 50% of the CapEx will be for Q1 is linked to the Gabon drilling program, with the balance primarily being in the FPSO finalization and towards the hookup. On Kossipo, for the full year, we're really -- the CapEx is kind of limited to just looking at preparation and development of the field development plan for submission. So that's really a limited amount of around $10 million. There's no -- until we get the field development plan in and approved, the future CapEx positions for Kossipo will then be established based on the approved field development plan.

And for the residual CapEx for drilling in Cote d'Ivoire in '27?

Yes. That is really down. And as I mentioned in my statement, we commenced the drilling in September with the batch setting of the top hole section. And then we're going to drill 1 well that we hope to have drilled and completed by late November in Q4. So the CapEx position for those batch drillings is going to be somewhere in the region of between $30 million and $45 million.

Remaining?

No, no. In Q4. In Q4. That would be our CapEx position for Q4 for that drilling program, the working interest for us.

I see. But then on those 6 wells and a few workovers you plan, there will be -- I'm just trying to equate what production could be looking like with remaining CapEx in '27 for that program. So I assume there will be still some completion work to be due in '27. Won't there be -- will there not be?

Absolutely. We've got a 5-well program. We'll only have 1 well down and in production in '26. The other 4 wells, bottom hole sections will be drilled in 2027.

And injectors.

Yes. Sorry, Thor's reminded me, we've also got 3 injectors to do as well.

I see. So assuming, say, $40 million per well gross, something like that?

No, we're probably closer to [indiscernible] per well gross. And obviously, we're 1/3 of that.

Yes. Okay. Okay. And my follow-up is a quick one is on Kossipo. So when would you see the big CapEx starting on Kossipo? Is that a '27 event, '28, later? I know first oil is in 2030.

It's going to be 2028. If you think of how we -- I mean, this is obviously a reasonable deepwater development and somewhere around 400, 500 meters of water depth. So when we get the field development plan, we're planning to have that submitted before the end of the year. One of the big issues here, if we can successfully get it submitted before the end of the year, that 2C contingent resource automatically drops into a 2P position for us on reserves. By the time we submit that plan and get it approved, we then can start the engineering phase. And the engineering phase will take probably at least between 6 to 12 months before we start any major CapEx commitments on equipment delivery. And obviously, at the same time, we then look to source a rig for the drilling activity. We also have to look at the position of how we're going to develop this field. At the moment, there's the opportunity to tie back into Baobab. So if we tie back into Baobab, we then got to take considerations for a suitable [ haulage ] in Baobab, the MV-10 production facilities. So it really is kind of -- we're looking at all the optionality right now as to how this fits in with the existing production profile of Baobab or if there's an accelerant opportunity on a stand-alone position on Kossipo. But that will all come out in the field development plan this year.

The next question is from Jeff Robertson with Water Tower Research.

Ron, a question on the guidance. Can you talk about the base Brent price forecast that's embedded in the NRI volume assumptions? And then just given the extreme volatility in crude prices, can you provide a bit of a refresher on how that flows through the PSCs with respect to NRI volumes and cost recovery?

Yes, I can do that. Underlying Brent assumptions that we assumed for 2026 was a baseline of $65, per Brent. And obviously, we got our differentials off of that. With regards to upside on that, obviously, the PSCs, the West Africa PSCs are very much a profit oil split. So we benefit from the rise in prices to the extent we have the hedges in place. Outside of that, Egypt, obviously, that PSC is somewhat very protective on lower oil prices. But on upper oil prices, the split between the excess cost oil that goes to the government versus the contractor is 85% to the state, 15% to the contractor. So the upside is somewhat limited in relation to the Egyptian barrels, although there is upside, but very, very weighted towards the contractor on the West Africa side.

And a question on Kossipo, George. And I guess on CI -705 as well. As you advance those projects, would you expect to maintain VAALCO's current working interest? Or at some point, would you get to a point where you'd consider trying to bring in another party to take a share of that risk?

Okay. On Kossipo, right now, we're more than comfortable at our 60% working interest and operatorship, and we've got an excellent relationship with our partner, PetroCI. So at this point, that's not currently in our plans, a farm-down position. I mean we have to bear in mind, we're looking at this opportunity, as we mentioned that in our releases that the appraisal well delivered over 7,000 barrels a day. So the size of the prize is very large for us. So obviously, it's going to be based upon the ranking of our investment opportunities and what comes out of the field development plan. On that basis, if it does look like it's going to be a rather heavily punitive CapEx position or it's going to have an elongated time line, we do take account of how long we have to invest the dollar before it comes back out of the ground, and that may drive a different decision-making process than we have currently planned. On CI-705, we have started the analysis on the prospectivity. We've -- we're working that up this year. We are very encouraged by what we see. What we have to bear in mind with CI-705 is that we have a block that's just under 2,500 square kilometers. It goes from the beach right through into water depths of in excess of 1,000 to 1,500 meters. So depending on where we see the most attractive targets -- and we see targets right now at the 200-meter level, and we see targets at the 1,300, 1,400-meter level. And it will really depend on which targets we want to exploit because obviously, the deeper we go, the more expensive it becomes. But if we're looking at the shallower targets as our first exploitation, I'm fairly confident we would keep that in-house. If it's a deeper target, then we'd certainly talk about farming out some of that position so we share the risk. The key here for us is we've built a position, as I mentioned earlier in today's call, in Cote d'Ivoire, a very hot area of activity, particularly by some of the IOCs, and we've got ourselves exceptionally well placed in those areas.

The next question is from Chris Wheaton with Stifel.

Two questions, if I may. Firstly, the roughly $150 million plus CapEx in Cote d'Ivoire this year, could you help break that down between what's left on the FPSO refurb project and the recommissioning, but then also the planned drilling later in the year? The second question was on free cash flow and your uses of free cash flow. If prices stay elevated and you do get -- I won't use the word windfall for obvious reasons -- you do get an extra $30 million to $40 million of, say, of free cash flow generated in the year, where do you apply that? How much could you actually reinvest quickly? How much would you want to keep on balance sheet given the volatility in prices and the fact -- and you've got a big CapEx program coming up? And how much might possibly be returned to shareholders? I'm interested in that sort of balance sheet sensitivity if you do get that higher free cash flows than originally planned for 2026. Those are my questions.

Okay. I'll take the CapEx flip one on the project. So as you know, the vessel is currently just rounding the Cape in South Africa. We've -- we're very pleased with the progress of that project. As you're all aware, the vessel sailed out of a rather hot area right now right before those activities kicked off, and we're very pleased that the vessel was well clear of those areas in a timely manner. With that, as we come around the Cape, we've got to put it back up on towards the Ivory Coast. And at that point, we've got basically the hookup and recommissioning to do on the vessel. So our position on that from where we are with the project right now is probably around about $50 million of that would be our share between the hookup and the recommissioning and getting the anchor changed and everything down on the vessel, with the balance being on the topside holes and the completion of the first well.

It's Ron, Chris. On the free cash flow question, obviously, when we talk about pay down debt, I mean, if we've got more free cash flow than we're projecting this year if oil prices remain high. But my aspect on that would be that we would not draw down as much, more than anything else. It's effectively, we would use that cash to not draw on the facility. So I don't think necessarily that we're looking to enhance the returns this year with our shareholders. We do have a high capital commitment. We're very much on track in these projects. And it's very much a story of growth into 2027. With the batch drilling, you're not going to see all of that production that CDI is going to give us until probably the end of Q1 into Q2 of next year. So very much, the free cash flow incremental will be used effectively not to draw as much debt.

Okay. That's great. Can I just have one follow-up, please, which is on Equatorial Guinea. If you do achieve FID this year, say, 4Q, which is what I think you've said, does that -- do you still leave you on track for first production by the end of 2028? Or does that slip into 2029, do you think?

I think currently on -- and I've got to be careful here because we haven't got to the full technical evaluation. But now that we're trying to understand the benefits of a vertical solution rather than one off the shelf, when we look at what's available in the marketplace to execute that solution, I'm still pretty comfortable that we will still be on track as we outlined in our Capital Markets Day for Equatorial Guinea development and production.

The next question is from Charlie Sharp with Canaccord.

I hate to do this, but I'd like to go back to the CapEx, if I may, and ask the question in a slightly different way. There are so many moving parts that it's difficult, at least for me, to kind of grasp exactly where you are on that. And I guess the question, therefore, I have is, in the [indiscernible] CMD, you indicated exactly what you expected the cost of the FPSO refurbishment, the Baobab Phase 5 drilling and the Gabon drilling programs to be net to yourselves. Nearly a year on from there. Can you quantify where those sit today and where the deltas are compared to what you said last year? And just also a little follow-up on -- I think Stephane asked about the spillover, if you like, into '27, and you went through that in terms of Cote d'Ivoire drilling. Is there going to be any spillover of the program in Gabon into next year, do you think?

Okay, Charlie, it's Ron here. So I think to give a bit more color on the CapEx side of things, the Baobab Ivorian FPSO rebuild, we kept it on schedule, as you know. Costs have increased in relation to the amount of steel work predominantly on that vessel. And I would say the gross costs that we've got predicted really for that with the operator is roughly about $80 million to $100 million higher than it was originally planned.

Of course, our share of that is 1/3.

Outside of that, the drilling is very much -- certainly from a CDI perspective, it's very much on what we said for the Capital Markets Day. In Gabon, obviously, we're a lot later in starting the program than we had expected when we did the Capital Markets Day back in May. That -- and we said it in the last call -- probably moved about $40 million to $50 million from 2025 into 2026. So there is a bit of a timing element there. The CapEx is the CapEx. Obviously, we've got an exploration expense in relation to the West Etame well, which was an exploration. Effectively, it was water wet. So we'll have that expense in Q1 of 2026.

On your second part of the question, Charlie, is -- no. Do we expect to see a rollover of the Gabon drilling program into 2027? That's an absolute no. We will have completed this program most likely in the early third quarter of 2026. And although Ron was mentioning on the exploration well, we -- I mean, that certainly has had a cash impact, but not on the CapEx side. But I mean, when we looked at the opportunity for that exploration well, it was definitely the right decision. And as I said earlier today, we optimized that well design to be able to reuse the top hole section to go back and drill the development well that we derisked on the pilots in December.

That's great. And one very short follow-up, if I may. Given the expectation for a second half weighted production uplift, could you give us some idea of where you see year-end '26 exit production at?

I think Ron's got the guidance, he's just looking at it now.

Charlie, again, we've only got the 1 well coming in from CDI in 2026 because obviously, they're batch drilling. But our working interest numbers will be somewhere between 25,000 and 26,000 barrels of oil equivalent on that exit rate.

The next question is from Bill Dezellem with Tieton Capital Management.

Let me start just from a big picture perspective with the Iran conflict. Is there any additional advantage in any way to having your production in West Africa, specifically Gabon, at this point?

That's an easy one. Obviously, our routes to monetize the crude in the export markets remain uninhibited by that particular activity and that conflict. So the advantage we would actually see is that what you're seeing reflective in the spot pricing for crude. Now as you're aware, our crude is based on Brent spot pricing. We have -- as Ron mentioned earlier today, we made sure we started to take advantage. And you've seen us do this many, many times in the previous years where we do have heavy CapEx programs. We do go out and protect our cash flow positions as best we can on a costless collar basis with the hedges. So ahead of this conflict in the Middle East, we -- Ron had secured significant positions to protect our cash flow on the costless collars through 2026 and into part of 2027. You can see that on our supplemental deck and on the earnings release. Anything out with that, obviously, we get and enjoy the upside of that. And that -- if the prices remain as high as they are at the moment, we will see additional cash coming in, in relation to particularly the Gabon and the Ivory Coast production levels -- sorry, cash levels for the production.

And so there is no additional price advantage to your location, it's just simply availability that you have, availability to get the crude to Europe or whatever market?

Yes. I mean -- it's Ron again, Bill. We could see the premium going on to the Brent price for the type of crude that we've got. I mean, the Gabon Etame crude, it's had a discount to Brent in 2025. But in previous years, we have seen some premiums. So it would not be out of the question for that premium to come back in. The big question here is what's going to happen with freight prices with a prolonged situation in the Gulf. So that's a $64,000 question. I think we're all playing with is what freight is going to do for those vessels.

All right. And so you have not seen that premium return yet?

No. We saw the differential at one point, I think it was last week, we saw WTI and Brent virtually get parity. So the differentials are going to move. We just haven't seen the effect -- the long-term effect yet, Bill. So it's something we're keeping a watch on.

Okay. And let me move to Egypt. Would you please discuss the exploration well in the H-Field in the Eastern Desert and that success and what the implications are for that new knowledge?

Yes, it's Thor here. Yes, we drilled into that zone, and we were a bit surprised, I guess, at the volumes that came in with that well. And I guess what's even more surprising is that the rates have sustained themselves quite high. So currently, what we're doing there is we're looking back at the seismic and doing the technical work on it to see if there's additional opportunities to drill further wells in the next well on that.

The next question is a follow-up from Stephane Foucaud with Auctus Advisors.

So following up on a question from Charlie about Gabon. Where would you see production settling at once the program is finished early [ 2003 ] in terms of production plateau at that point? And then I have a question about interest.

Okay. I mean, on a -- I mean, as you know, we're drilling, so I'm kind of being a bit speculative. On a successful case basis, we're currently somewhere in the region between 14,000 and 16,000 barrels a day gross. I would expect to be somewhere between 20,000 to 23,000 barrels a day on completion of the program. It really is dependent on two things. One is within that program, we are currently considering to drill a gas well, and that gas well will enhance the gas availability for gas lift and gas injection and field fuel in the Etame field. And currently, the more gas we can deliver into the existing production wells, the higher we can cycle the compressors, and therefore, we will have enhanced oil recovery from existing production, which is completely separate from the new wells we're going to drill. The second part of that is when we go to drill the 5H well in Ebouri, we are going back into that structure that we really haven't looked at for over 10 years. We've got some estimates as what we consider this well may be able to perform, but the upsides of those estimates, the range is fairly large. So depending on what we encounter in that far reach well on 5H, it could have a meaningful change in the production. But rule of thumb, I would expect to be between 20,000 and 23,000 a day gross out of Gabon at the end of the program.

I guess one thing that we're pretty happy with is that on the Ebouri field specifically, the continued performance of the 2H well, as well as the 4H well, which I think you're probably aware of, we brought on a year ago under a test program. That well is still flowing at a pretty good rate. So we're pretty happy with what we're seeing out of Ebouri right now and expect that next well to be good as well.

And a quick one for Ron. The -- in the -- so the CapEx includes capitalized interest, $20 million or so. So I assume this is not cash. This is something that -- it's an accounting CapEx, for lack of a better word, correct?

It is. And you'll see on Slide 11, how we split out the CapEx by country, and we've kept the sort of wedge in relation to capitalized interest. I may have to correct you. I mean, it is cash. It's whether you pay the bank or whether you're paying for the CapEx, the cash does leave the bank, unfortunately.

The next question is from Aaron Schafer with Kornitzer Capital.

What prices did you realize during the quarter for your oil? And then as my follow-up, what prices are you realizing thus far this year?

Okay. We're just getting that schedule. I mean, the -- again, if you look into the earnings release, Aaron, on Page 5, we give a breakdown of the 3 months through the 31st of December. And you can see the realized prices that we got for our crude right across our asset basis there. So Gabon, it was about $58; Egypt, $54; and Canada, $53. So again, it was quite -- it was obviously a suppressed market as we went through the end of 2025. You should see obviously that coming up in Q1 2026.

This concludes the question-and-answer session. I would like to turn the conference back over to George Maxwell for any closing remarks.

Thank you very much, operator. I'd like to thank everyone for joining us today in our 10-K -- 2025 earnings call. I think when we entered 2025, there was a lot of speculation about the size of projects that we were undertaking and the size of CapEx spend we had in 2025. And I guess a lot of risk factors added on to our ability to execute and deliver through 2025 on these major projects while still maintaining the returns to our shareholders through dividends and keeping a very prudent position around the balance sheet. And I think when we look at the results for 2025, it's very clear we've achieved exactly what we said we were going to do when we had this call -- the similar call 12 months ago. Now we're now in a position where when we look at the project in Cote d'Ivoire, that's significantly derisked with the vessel on its way back and production lined up to begin again in Q2. So when we look at the CapEx year for 2026, we don't have a significant development CapEx, i.e., a major project of construction. What we do have are major CapEx investments in drilling activity to add liquid production to our production facilities and therefore, cash -- significant cash generative opportunities. Given where we are on these projects, although we have a significant CapEx spend planned for 2026, that is money going into the ground to come back out in cash in the near term. And that's a significant difference to the type of projects we were executing in 2025, which were development capital projects for construction of production facilities. So I think we've demonstrated the success of our ability to manage and work with our partners to achieve the successes that you see in 2025. And I think we should hope -- the market should have confidence in our ability when we go through the drilling activities, both in Gabon and with our partners in Egypt and in Cote d'Ivoire, that we will be successfully executing those in 2026. So with that, I'd like to thank everyone. I think we've had a very successful 2025. The diversification and derisking of the company's cash flows and production opportunities is starting to pay dividends for us, and we'll continue to see that grow through '26 and into '27. Thank you very much.

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