VAALCO (EGY) Q4 2025 Earnings Call Transcript

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DATE

Mar. 13, 2026 at 10 a.m. ET

CALL PARTICIPANTS

• Chief Executive Officer — George Maxwell
• Chief Financial Officer — Ronald Bain
• [Unspecified Egypt Team Representative] — Stuart

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TAKEAWAYS

• Adjusted EBITDAX -- $173.4 million for the year, contributing to a three-year cumulative of over $750 million and surpassing management’s midyear guidance midpoint.
• Net Cash from Operating Activities -- $212.7 million for 2025, supporting continued capital expenditures and shareholder returns.
• Net Income / Net Loss -- Annual net loss of $41.4 million driven by a fourth-quarter net loss of $58.6 million, primarily due to a non-cash impairment charge of $67.2 million related to the sale of Canadian assets.
• Dividend Returned to Shareholders -- $26.5 million paid in 2025, with $0.0625 per share distributed in the fourth quarter; more than $150 million paid out via dividends and buybacks since Q4 2021.
• Production -- 16,556 net revenue interest barrels of oil equivalent per day and 21,160 working interest barrels of oil equivalent per day, both above the increased midpoint of company guidance.
• Sales Volume -- 17,452 net revenue interest barrels of oil equivalent per day, above the high end of increased 2025 guidance range.
• Operating Cost -- Absolute production expense of $158 million and per-barrel production cost of $24.89 (up from $22.48 in 2024), while keeping overall costs in line with guidance.
• Cash G&A -- Came in below the low end of guidance for both the fourth quarter and the full year.
• Unrestricted Cash -- $58.9 million at December 31, 2025, up nearly $35 million from the prior quarter.
• Reserve-Based Lending Facility -- New facility reached $255 million in current commitments at year-end, with $60 million drawn and an undrawn capacity up to $300 million.
• SEC Proved Reserves -- 43 million barrels of oil equivalent at year-end, a 5% decrease, but included 4 million barrels of positive revisions, additions, and extensions offsetting two-thirds of 2025 production.
• SEC Proved Reserve PV-10 -- $410 million at year-end, up 8% from $379 million, attributed to positive revisions despite lower average pricing and wider differentials in Gabon.
• Proved Developed/Undeveloped Reserves -- 17.5 million barrels of oil equivalent (developed) and 25.5 million barrels of oil equivalent (undeveloped).
• 2P CPR Reserves -- 73.7 million barrels of oil equivalent, down 6%, but 2P CPR PV-10 increased 26% to $859 million.
• Canadian Asset Divestment -- $25.5 million sale finalized in February 2026, equivalent to 2.7x trailing twelve months operational cash flow, with prior production of 1,850 barrels per day and nearly $65 million in cumulative operating cash flow delivered since acquisition.
• Côte d’Ivoire Portfolio -- Company secured operatorship and 60% working interest in Kisipo field (estimated 102 million barrels 2C resources and 293 million barrels oil equivalent in place), added Block CI-705 (70% working interest), and holding a 10-year license extension at Baobab to 2038.
• Baobab FPSO Status -- FPSO refurbishment was completed in Dubai; vessel en route back to Côte d’Ivoire and field restart expected in Q2 2026, with development drilling to follow and at least one new well planned to be onstream by year-end.
• Gabon Operations -- Full-field maintenance shutdown completed; Phase 3 drilling initiated, with the 15H-ST development well drilled and an exploration well found to be non-commercial, but sidetracked for further development drilling in 2026.
• Egypt Performance -- 20 wells drilled in 2025, raising production to over 11,000 barrels of oil per day in Q1 2026, exceeding the 10,700-barrel budget; all receivables with EGPC brought current, reducing year-end balance to $31 million from $113 million.
• Exploration Costs -- Fourth-quarter expense of $6 million for seismic in Gabon and Côte d’Ivoire and an Egyptian well; full-year 2026 exploration outlay expected between $30 million and $35 million.
• Guidance for 2026 Production -- Projected between 20,100–22,400 working interest barrels per day and 16,100–17,950 net revenue interest barrels per day; Q1 made lower by Canadian sale and field restarts.
• CapEx Guidance for 2026 -- $290 million to $360 million total capital spending, with $90 million to $110 million for Q1 2026 (including ~$3 million capitalized interest in Q1, $22 million–$24 million for the full year).
• Hedging for 2026 -- Approximately 50% of production hedged using collars with a $65 per barrel floor for the balance of 2026; company indicated ongoing monitoring due to price volatility and geopolitical developments.
• Baobab FPSO Refurbishment Cost -- Gross project cost expected to be $80 million–$100 million higher than original estimate, with VAALCO’s share one-third of that amount.
• Gabon Drilling Deferral -- Delay moved $40 million–$50 million of CapEx originally planned for 2025 into 2026.
• Year-End 2026 Production Exit Rate -- Expected to be between 25,000–26,000 working interest barrels of oil equivalent per day.

SUMMARY

VAALCO Energy (NYSE:EGY) reported results above management’s guidance on production, sales, and adjusted EBITDAX, although the year ended with a net loss caused by a non-cash impairment from the Canadian asset sale. The company achieved significant operational milestones, including successful field maintenance, major drilling activity, and strategic divestitures and acquisitions in Côte d’Ivoire, Gabon, and Egypt. Management confirmed substantial capital investment in 2026, with a focus on drilling rather than major infrastructure construction, supporting expectations for higher production and reserve additions as new wells come online.

• The company reduced outstanding accounts receivable from Egyptian General Petroleum Corporation to $31 million at year-end, a decline from $113 million, while collecting over $210 million during 2025.
• Management cited a 10-year license extension for Baobab field in Côte d’Ivoire to 2038 and plans to batch drill five wells, with only one well fully completed and onstream by year-end 2026.
• Guidance reflects volatility and timing effects, with Q1 sales volumes lower than production due to a single state lifting in Gabon, but five optimized liftings in 2026 should normalize future quarters.
• The non-commercial outcome of the West Etame exploration well in Gabon will result in a sidetrack development well utilizing the existing wellbore; $6 million in exploration expense for the fourth quarter included seismic costs in Gabon and costs associated with an Egyptian exploration well.
• For the Kisipo field, management expects major CapEx to begin only after field development plan approval, likely no earlier than 2028, with 2C resources of 102 million barrels of oil equivalent and 293 million barrels of oil equivalent in place.
• Management established baseline 2026 guidance on a Brent crude price of $65 per barrel, highlighting profit oil split sensitivity in West African PSCs and indicating that hedging strategies are used to protect cash flow during volatility.

INDUSTRY GLOSSARY

• FPSO (Floating Production Storage and Offloading): A vessel used in offshore oil production to process and store hydrocarbons before transfer to tankers.
• PSC (Production Sharing Contract): Contract structure with host governments assigning cost recovery and profit oil allocation between operators and the state.
• 2C Resources: Best estimate of contingent resources, considered potentially recoverable if development hurdles are overcome.
• 2P CPR (Proved + Probable Competent Person’s Report): Management-prepared estimate of combined proved and probable reserves, before royalty deduction.
• PV-10: Present value of estimated future oil and gas revenues, discounted at 10%, excluding income taxes.
• Liftings: Shipments of crude oil agreed with host governments or counterparties under contractual allocation.
• Capitalized Interest: Interest cost added to capital project expenditures instead of expensed, reflecting funds used for ongoing development.

Full Conference Call Transcript

George Maxwell, our CEO, will review key highlights of the fourth quarter. Ronald 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 reenter 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, 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-Ks for the year ended 2025 we expect to file on or before 03/16/2026. Investors are cautioned that forward-looking statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements.

VAALCO Energy, Inc. 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-Ks. 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.

George Maxwell: Thank you, Al. Good morning, everyone, and welcome to our fourth quarter and full year 2025 earnings conference call. Over the past three 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 and has allowed us to expand our portfolio and also to fund organic growth initiatives, better positioning VAALCO Energy, Inc. for the future. We recently divested all of our Canadian assets and we added to our Côte d’Ivoire position by being named operator with a 60% working interest in the Kisipo field on Block CI-40.

Last year, we added an exploration block, CI-705, in Côte d’Ivoire and are working with our partners on the seismic acquisition and processing at Niosi Marine and Guduma Marine 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 Côte d’Ivoire we have created a more balanced portfolio between production, development and high-quality prospective assets. We have accomplished many things in these past five years, growing VAALCO Energy, Inc. 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, been committed to returning cash to shareholders. In 2025, we returned another $26.5 million in dividends and since Q4 2021, we have returned over $150 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 Energy, Inc. 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.

This means that the meaningful production uplift we are projecting from these major projects will not 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 Côte d’Ivoire. I would like to remind you that we had no production or interest in Côte 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 timeline, the FPSO at Baobab ceased hydrocarbon operations as scheduled on 01/31/2025 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 en route back to Côte 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 three producers, two to three injectors and two workovers providing potential meaningful additions to production from the main Baobab field where we have a ten-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 five wells. The completions will then be commenced and we expect at least one well to be on full production by year end.

In March 2025, we announced a formal agreement for the CI-705 block offshore Côte 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 two 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 STOIIP. 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 Energy, Inc. and PETROCI elected a sole-risk development of the Qasepo field. In February 2026, VAALCO Energy, Inc. was confirmed with a 60% working interest in the Kisipo field on the CI-40 block just eight 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 de-risk and enhance our evaluation and development plan. The field was discovered in 2002 with the Kisipo-1X well and later appraised in 2019 with the Kisipo-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. So in less than two years, we have established a sizable position in Côte 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 volume through accretive acquisitions, and we are excited about the prospects in Côte d’Ivoire. Moving to Gabon, given that we have not drilled a well in Gabon in over three 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 in Gabon since the FSO was brought online in 2022. In late 2025, we began our Phase 3 drilling program in Gabon with the drilling of two pilot wells in the Etame Field. Based on the pilot well results, we proceeded with the drilling of the 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 not commercial. 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 de-risked 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 Marine and Guduma Marine, we are working with our partners and the operator on plans for the two blocks moving forward.

We commenced a seismic survey in November 2025 which was completed in 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 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 eight 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 late 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. Ronald will discuss this in more detail, but we are now essentially on a current billing basis with EGPC. On 02/05/2026, 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 2.7 times our trailing twelve 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 Ronald 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 had 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 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 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 are 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 Ronald, 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 Energy, Inc.'s year-end SEC reserves for over sixteen 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 two-thirds of our 2025 production of 6 million barrels of oil equivalent. Also, with the Phase 3 drilling program in Gabon 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 17.5 million barrels of oil equivalent in proved developed reserves and 25.5 million barrels of oil equivalent in proved undeveloped reserves. Turning to a 2P CPR estimate, which includes proven and probable reserves using VAALCO Energy, Inc.'s management’s assumptions for future pricing and cost reported on our 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 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 reserve, 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 have been focused on growing production, reserves, and value for our shareholders. I would 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 Ronald to share our financial results.

Ronald Bain: 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 barrels of oil equivalent per day, or 21,160 working interest barrels of oil equivalent per day, both above the midpoint of VAALCO Energy, Inc.’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 non-cash 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 nine months of 2025, we ended the year with a net loss of $41.4 million driven by the fourth quarter and the non-cash 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 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 is 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 timing 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 have 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. 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 Energy, Inc.’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 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 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 and cash balance to fund our active capital programs in Gabon and Côte d’Ivoire. As expected, during 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 Energy, Inc. 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 will 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 February and we are forecasting the Baobab field in Côte d’Ivoire coming back online in Q2. So there are some ups and downs in production and sales for 2026. But we expect both to increase materially in 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 five optimized liftings in the year with the timing one 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 oil expense to be in the range of $23.50 to $31 per net revenue interest barrel of oil equivalent. We are also expecting slightly higher absolute cash G&A in 2026.

For exploration expense, taking into account the seismic work in Gabon and Côte 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 Côte d’Ivoire, continue recompletions in Egypt, and begin spending in Kisipo.

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 have 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 have delivered and are very well positioned to continue to execute at a high level across our diversified assets over the next several years. With that, I will now turn the call back over to George.

George Maxwell: Thanks, Ronald. 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 five 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 Energy, Inc. 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, Inc. 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 Baobab is nearly back in Côte 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 five-well development drilling program that is scheduled to begin later this year.

At Kisipo, we are very excited to be named operator with a 60% working interest and we are working on a field development plan 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 conducting further geological evaluations on 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 are 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 three 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 Energy, Inc. as we execute on our organic opportunities over the next few years. Thank you and with that, operator, we are ready to take questions.

Operator: We will now begin the question-and-answer session. To ask a question, if you are using a speakerphone, please pick up your handset before pressing the keys. If you have additional questions, you may rejoin the queue. Our first question today is from Stephane Foucaud with Octus Advisors. Please go ahead.

Stephane Foucaud: Hi, guys. Thanks for taking my question. So I have a question around CapEx in Côte d’Ivoire. And perhaps if you could provide a bit more granularity on how it is placed? In other words, what is FPSO, what is drilling, what is maybe possible, and more importantly, how much CapEx you would expect, or residual CapEx you would expect in 2027 for this drilling program that you would start in 2026 in Côte d’Ivoire? And I have a follow-up on Côte d’Ivoire. Thank you.

George Maxwell: Thank you, Steph. Well, obviously the guidance we have been giving for Q1 in relation to the CapEx, the majority of that is split between the drilling program in Gabon and the hookup for the FPSO in Côte d’Ivoire. So at that point, we expect around 50% of the CapEx for Q1 is linked to the Gabon drilling program, with the balance primarily being in the FPSO finalization and towards the hookup. On Qasepo for the full year, really the CapEx is limited to just looking at preparation and development of the field development plan for submission. So that is a limited amount of around $10 million.

There is no CapEx until we get the field development plan in and approved. The future CapEx positions for Kisipo will then be established based on an approved field development plan.

Stephane Foucaud: Thank you. And for the residual CapEx for drilling in Côte d’Ivoire in 2027?

George Maxwell: Yes, that is really down, and I mentioned in my statement, we commence the drilling in September with the batch setting of the top hole section. Then we go in to drill one well that we hope to have drilled and completed by late November in Q4. And so the CapEx position is going to be somewhere in the region of $30 million to $45 million in Q4. That would be our CapEx position for Q4 for that drilling program, the working interest for us.

Stephane Foucaud: I see. Thank you. But then on those six wells and few workovers you plan, there would be—I am just trying to equate what production could be looking like with remaining CapEx in 2027 for that program. So I assume there will be still some completion work to be due in 2027. Will there not be?

George Maxwell: Absolutely. We have a five-well program. We only have one well down and in production in 2026. The other four wells’ bottom hole sections will be drilled in 2027. Injectors. Yes. Sorry. Restores remind me. We have also got three injectors to do as well.

Stephane Foucaud: I see. So assuming, say, $1 million per well gross, something like that?

George Maxwell: No, we are probably closer to $6 million per well gross and obviously we are one third of that.

Stephane Foucaud: Yes. Okay. Okay, thank you. And my follow-up is a quick one on Kisipo. So when would you see the big CapEx starting on Kisipo? Is that a 2027 event, 2028, later? I know first oil is 2030.

George Maxwell: It is going to be 2028. If you think of how we—this is obviously reasonably deepwater development in somewhere around 400 to 500 meters of water depth. When we get the field development plan, we are 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 moves 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 six to twelve months before we start any major CapEx commitments on equipment delivery and obviously at the same time we have then got to source a rig for the drilling activity. We also have to look at the position of how we are going to develop the field. At the moment, there is the opportunity to tie back into Baobab. So every time back into Baobab, we are then going to take considerations for suitable ullage in Baobab, the MV10 production facilities.

So it really is kind of—we are looking at all the optionality right now as to how this fits in with the existing production profile of Baobab or if there is an excellent opportunity on a standalone position on Kisipo. But that will all come out in the field development plan this year.

Stephane Foucaud: Thank you.

Operator: The next question is from Jeff Robertson with Water Tower Research. Please go ahead.

Jeff Robertson: Thank you. Good morning. Ronald, a question on the guidance. Can you talk about the base Brent price forecast that is 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?

Ronald Bain: 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, 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, or 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, it is very, very weighted towards the contractor on the West Africa side.

Jeff Robertson: And a question on Kisipo, George. And I guess on CI-705 as well. As you advance those projects, would you expect to maintain VAALCO Energy, Inc.’s current working interest or at some point would you get to a point where you would consider trying to bring in another party to take a share of that risk?

George Maxwell: Okay. On Kisipo right now, we are more than comfortable at our 60% working interest and operatorship and we have got an excellent relationship with our partner PETROCI. So at this point, that is not currently in our plans—a farm-down position. We have to bear in mind, we are looking at this opportunity as we mentioned in our releases, the appraisal well delivered over 7,000 barrels a day. So the size of the prize is very large for us. So obviously, it is going to be based upon the ranking of our investment opportunity and what comes out of the field development plan.

On that basis, if it does look like it is going to be a rather heavily punitive CapEx position or it is going to have an elongated timeline—you know, 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 an analysis on the prospectivity. We are 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 is 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. 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 would really depend on which targets we want to exploit because obviously the deeper we go the more expensive it becomes. But if we are looking at the shallower targets as our first exploitation, I am fairly confident we would keep that in-house. If it is a deeper target, then we would certainly talk about farming out some of that position so we share the risk.

The key here for us is we have built a position, as I mentioned earlier in today’s call, in Côte d’Ivoire, a very hot area of activity particularly by some of the IOCs. We have got ourselves exceptionally well placed in those areas.

Chris Wheaton: Thanks. Good morning, guys. Thanks very much indeed for the call. Two questions, if I may. Firstly, the roughly $150 million-plus CapEx in Côte d’Ivoire this year—could you help break that down between what is 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 a—I will not use the word windfall for obvious reasons—you do get an extra $30 million to $40 million, 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 you have a big CapEx program coming up and how much might possibly be returned to shareholders? I am interested in that sort of balance sheet sensitivity if you do get that higher free cash flow than originally planned for 2026. Those are my questions. Thank you.

George Maxwell: Okay. I will take the CapEx split one on project. So as you know, the vessel is currently just rounding the Cape in South Africa. We are very pleased with the progress of that project. As you are all aware, the vessel sailed out of a rather hot area right now, right before those activities kicked off and we are very pleased that the vessel was well clear of those areas in a timely manner. With that, as we come around the Cape, we have got to pull it back up towards Ivory Coast and at that point, we have got basically 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 $50 million of that would be our share between the hookup and recommissioning and getting the anchor chains and everything down on the vessel, with the balance being on the topside holes and the completion of the first well.

Ronald Bain: Yes. Chris, on the free cash flow question, obviously, when we talk about pay down debt—if we have got more free cash flow than we are projecting this year if oil prices remain high—my aspect on that would be that we would not draw down as much debt more than anything else. Effectively we would use that cash to not draw on the facility. So I do not think that we are looking to enhance the returns this year with our shareholders. We do have a high capital commitment. We are very much on track in these projects. It is very much a story of growth into 2027.

With the batch drilling, you are not going to see all of that production that Côte d’Ivoire 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.

Chris Wheaton: Okay. That is great. Thank you. Can I just have one follow-up, please, which is on Equatorial Guinea. If you do achieve FID this year, say Q4, which is what I think you have said, does that still leave you on track for first production by 2028? Or does that slip into 2029, do you think?

George Maxwell: I think currently—and I have to be careful here because we have not got to the full technical evaluation—but now that we are trying to understand the benefits of a subsea solution rather than one on the shelf, when we look at what is available in the marketplace to execute that solution, I am still pretty comfortable that we will still be on track as we outlined in our Capital Markets Day for Equatorial Guinea development and production.

Chris Wheaton: Okay. That is great. Brilliant. Thanks very much, guys.

Ronald Bain: Thanks, Chris.

Operator: The next question is from Charlie Sharp with Canaccord. Please go ahead.

Charlie Sharp: Yes, morning and thank you very much for taking my question, and thank you for a comprehensive presentation as well. I hate to do this, but I would 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 is 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 new 2025 CMD, you indicated exactly what you expected the costs of the FPSO refurbishment of 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 2027. And you went through that in terms of Côte d’Ivoire drilling. Is there going to be any spillover of the program in Gabon into next year, do you think?

Ronald Bain: Okay, Charlie, it is Ronald here. So I think to give a bit more color on the CapEx side of things, the Baobab FPSO rebuild—we have 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 cost that we have 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 one third. Outside of that, the drilling is very much—certainly from a Côte d’Ivoire perspective—it is very much on what we said for the Capital Markets Day.

In Gabon, obviously we are 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 have got an exploration expense in relation to the West Etame well, which was an exploration. Effectively, it was water wet. So we will have that expense in 2026.

George Maxwell: On your second part of the question, Charlie—no, do we expect to see a rollover of the Gabon drilling program into 2027? That is an absolute no. We will have completed this program most likely in 2026. And although Ronald was mentioning on the exploration well, that certainly has had a cash impact but not on the CapEx side. But 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 de-risked on the pilots in December.

Charlie Sharp: That is 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 2026 exit production at?

Ronald Bain: I think Ron’s got the guidance sheet—he is just looking at it now. Charlie, again, we have only got the one well coming in from Côte d’Ivoire in 2026 because obviously they are batch drilling. Our working interest numbers will be somewhere between 25,000–26,000 barrels of oil equivalent on that exit rate.

Charlie Sharp: Wonderful. That is very helpful. Thank you.

Operator: The next question is from Bill Dezellem with Tieton Capital Management. Please go ahead.

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

George Maxwell: That is an easy one. Obviously, our routes to monetize the crude in the export markets remain uninhibited by that particular activity in that conflict. So the advantage we would actually see is that what you are seeing is reflective in spot pricing for crude. Now as you are aware, our crude is based on Brent spot pricing. We have, as Ronald mentioned earlier today, made sure we started to take advantage—and you have seen us do this many, many times in the previous years—when 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 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 outside of that, obviously we get and enjoy the upsides of that and if the prices remain as high as they are at the moment, we will see additional cash coming in, in relation to particularly Gabon and the Ivory Coast production levels. Sorry, cash levels for the production.

Bill Dezellem: Thank you. And so there is no additional price advantage to your location. It is just simply availability that you have, availability to get the crude to Europe or whatever market.

Ronald Bain: Yes. It is Ronald again, Bill. We could see the premium going on to the Brent price for the type of crude that we have got. I mean, the Gabon Etame crude has 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 is going to happen with freight prices with a prolonged situation in the Gulf. So that is the $64,000 question I think we are all playing with—is what freight is going to do for those vessels.

Bill Dezellem: All right. Thank you. And so you have not seen that premium return yet?

Ronald Bain: No, we saw the differential at one point—I think it was last week—saw WTI and Brent virtually get parity. So the differentials are going to move. We just have not seen the long-term effect yet, Bill. So it is something we are keeping a watch on.

Bill Dezellem: 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.

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

Operator: Next question is a follow-up from Stephane Foucaud with Octus Advisors. Please go ahead.

Stephane Foucaud: Yes, hi again. Thank you. So following up on a question from Charlie about Gabon, where would you see production setting at once the program is finished early 2026 in terms of a production plateau at that point? And then I have a question about interest.

George Maxwell: Okay. I mean, as you know, we are drilling, so I am being a bit speculative on a successful case basis. We are currently somewhere in the region between 14,000–16,000 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 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; this is completely separate from the new wells we are going to drill. The second part of that is, when we go to drill the 5H well at Ebouri, we are going back into that structure that we really have not looked at for over ten years. We have got some estimates as to 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 20,000–23,000 a day gross out of Gabon at the end of the program.

Stuart: I guess one thing that we are 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 are probably aware of—we brought it on a year ago under a test program. That well is still at a pretty good rate. So we are pretty happy with what we are seeing out of Ebouri right now and expect that next well to be good as well.

Stephane Foucaud: Thank you. And a quick one for Ronald. In the CapEx, the CapEx includes capitalized interest, $20 million or so. So I assume this is not cash. This is something that—it is an accounting CapEx, for lack of a better word. Correct?

Ronald Bain: It is, and you will see on slide 11 how we split out the CapEx by country, and we have got the sort of wedge in relation to capitalized interest. I may have to correct you. I mean, it is cash. It is whether you pay the bank or whether you are paying for the CapEx. The cash does leave the bank, unfortunately.

Stephane Foucaud: I see. Okay. Thank you. Thank you.

Operator: The next question is from Aaron Schafer with Kornit’s Capital. Please go ahead.

Aaron Schafer: 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?

George Maxwell: Okay. We are just getting that schedule.

Ronald Bain: Again, if you look into the earnings release, Aaron, on page five, we give a breakdown of the three months through December 31. You can see the realized prices that we got for our crude right across our asset bases there. So Gabon, it was about $58; Egypt, $54; and Canada, $53. So again, it was obviously a suppressed market as we went through 2025. You should see that coming up in Q1 2026.

Aaron Schafer: Okay, thanks. That is all I have got. Thank you.

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

George Maxwell: Thank you very much, operator. I would like to thank everyone for joining us today in our 10/2025 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 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 is very clear we have achieved exactly what we said we were going to do when we had this call, the similar call twelve months ago. Now we are in a position where we look at the project in Côte d’Ivoire that is significantly de-risked with the vessel on its way back and production lined up to begin again in Q2. So when we look at the CapEx year 2026, we do not 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 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 is a significant difference from the type of projects we were executing in 2025, which were development capital projects for construction of production facilities. So I think we have demonstrated the success of our ability to manage and work with our partners to achieve the successes that you see in 2025.

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 Côte d’Ivoire that we will be successfully executing those in 2026. So with that, I would like to thank everyone. I think we have had a very successful 2025. The diversification and de-risking of the company’s cash flows.

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