EGY - NYSE

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.