Vaalco Energy EGY Q1 2026 Earnings Transcript

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DATE

Friday, May 8, 2026 at 9 a.m. ET

CALL PARTICIPANTS

• Chief Executive Officer — George Maxwell
• Chief Financial Officer — Ronald Y. Bain

TAKEAWAYS

• Net Loss -- $93.7 million driven by $71 million in derivative losses and $22.4 million in exploration expense.
• Derivative Losses -- $15 million in realized hedging losses and $56 million in unrealized hedging losses, primarily due to oil price volatility since March.
• Exploration Expense -- $22.4 million, below prior guidance range of $27 million to $32 million, with most annual exploration expense incurred in Q1.
• Production Volumes (NRI BOE/day) -- 15,110, above the midpoint of guidance.
• Sales Volumes (NRI BOE/day) -- 12,160, slightly above guidance midpoint but notably lower than production due to Gabon lifting timing.
• Adjusted EBITDAX -- $11.6 million, reflecting lack of partner liftings in Gabon and no Côte d’Ivoire sales.
• Production Guidance Increase -- Full-year 2026 production and sales NRI volumes raised by 8%-12% due to successful drilling and Baobab restart.
• CapEx -- $78.1 million in Q1 cash spend, below guidance due to project timing; full-year capital guidance remains unchanged despite program additions.
• Unrestricted Cash -- $48 million at quarter-end, with $92 million drawn on reserve-based lending facility; net debt of $104 million.
• Q2 Sales Outlook -- Expected 44% higher midpoint NRI volumes compared to Q1, driven by two partner liftings in Gabon and Côte d’Ivoire production resuming.
• Q2 Production Guidance (NRI BOE/day) -- Range of 16,800 to 18,700; Working interest guidance: 21,600 to 23,800 BOE/day.
• Production Cost Guidance -- Q2 cost expected at $26–$31 per NRI BOE, higher than Q1 mainly due to increased West African mix and fuel costs.
• Cash G&A -- $6.9 million in Q1, beneath the low end of guidance.
• Canadian Asset Sale -- Completed exit from Canada in February, with no future contribution to guidance.
• Dividend Payment -- Quarterly cash dividend of $0.0625 per share, totaling $6.7 million, announced again for Q2.
• Baobab FPSO Status -- Refurbishment completed on schedule, with field restart and production slated for June and sales commencing in Q3.
• Kossipo Field Operator Status -- VAALCO Energy now operator with a 60% working interest and estimated gross 2C resources of 102 million BOE.
• Gabon Drilling Update -- Etame 14H-8 well brought online in late April at 4,850 gross barrels/day, with two months of contribution in the coming quarter.
• Egypt Drilling -- Six-well program begins in Q2, with 2026 CapEx guidance unchanged and anticipated production rise starting Q3.
• Exploration Drilling Timing (Gabon, Nyonie/Gnondo) -- Earliest commitment well may occur in late 2027 or 2028, pending seismic processing and opportunity scheduling.

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RISKS

• Ronald Y. Bain said, "with the uncertainty in macro events and oil pricing our realized and unrealized derivative losses could continue to impact earnings in the coming quarters."
• Production expense is expected to increase in Q2 "primarily related to fuel costs and reflects a higher mix of West African barrels."
• Income tax expense included a $2.9 million unfavorable oil price adjustment owing to changes in the valuation of government-allocated profit oil.

SUMMARY

VAALCO Energy (NYSE:EGY) recorded a substantial net loss for the quarter, primarily due to significant derivative and exploration charges, but Q2 guidance signals a marked recovery as major operational catalysts come online. Management confirmed the successful completion of the Baobab FPSO refurbishment, with production restart scheduled for June and sales commencement in Q3, setting the stage for increased company-wide output. Full-year production and sales guidance was raised, underpinned by robust drilling results in Gabon and Egypt, and by new operator status and resource upgrades at promising Côte d’Ivoire assets.

• Ronald Y. Bain cited expected production exit rates of "between 25,000 and 27,000 barrels" per day, with additional upside possible if flush production at Baobab outperforms guidance.
• Quarterly hedge coverage was at 56% of guided Q1 barrels, primarily with costless collars, and with substantial loss exposure due to recent Brent volatility.
• Dividend distributions continue, signaling ongoing capital returns to shareholders, amidst heavy investment in new wells and infrastructure.
• Receivables from Egypt were reduced by $7.4 million over the quarter, as collections exceeded revenue, improving working capital efficiency.
• Partner liftings in Gabon will recur "every other month" through the end of the year, supporting steadier sales recognition as timing normalizes.

INDUSTRY GLOSSARY

• FPSO: Floating Production, Storage, and Offloading vessel used to process and store oil or gas offshore before offloading to tankers.
• NRI: Net Revenue Interest, representing the company’s share of production after royalties and government take.
• 2C Resources: Best estimate of contingent resources—hydrocarbons potentially recoverable but not yet classified as reserves due to one or more contingencies.
• 2P Reserves: Proved plus probable reserves, reflecting a higher degree of certainty than 2C resources.
• Liftings: Discrete sales of crude oil allocated from joint production or by government share, often referenced in cargo units.
• FEED: Front-End Engineering and Design, early technical work done to define and cost new projects.

Full Conference Call Transcript

George Maxwell, our CEO, will review key highlights of the first quarter. Ronald Y. 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, comparisons, and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements.

Investors are cautioned that forward-looking statements are not guarantees of future performance and 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. Please note that this conference call is being recorded. Let me turn the call over to George.

George Maxwell: Thank you, Chris. Good morning, everyone, and welcome to our first quarter 2026 earnings conference call. Over the past two years, we have streamlined and expanded our portfolio while delivering consistently solid operational results. In February 2026, we divested all of our Canadian assets and simultaneously added to our Côte d’Ivoire position by being named operator with a 60% working interest in the Kossipo field on CI-40 block. We are actively evaluating and processing seismic with our partners in Nyonie Marine and Gnondo Marine blocks offshore Gabon and on our exploration block CI-705 in Côte d’Ivoire.

At Etame, we have had several successful wells drilled and the rig has now moved to Avouma to drill the next well in our drilling campaign. The Baobab FPSO has successfully completed its refurbishment and is now moored back into position with wells being reconnected and production expected to resume in early June. 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.

First quarter 2026 was a pivotal quarter operationally and we are beginning to see the significant production uplift we are projecting from these major projects in Q2 2026 and expect it to continue into 2027. We are confident in our ability to execute and have increased our full-year 2026 production and sales guidance, and added to our work program without increasing our capital expenditure guidance. I would now like to provide a quick update on our diverse portfolio of high-quality assets beginning with Côte d’Ivoire. I would like to remind you that we had no assets in Côte d’Ivoire prior to April 2024. Since that time we have developed a significant and prospective portfolio.

In line with the project timeline, the FPSO at Baobab ceased hydrocarbon operations in January 2025. Following a year of refurbishment in Dubai, the FPSO returned to Côte d’Ivoire in April and is now moored into position and we have four out of the seven risers and umbilicals connected. We expect the field to restart production in June with sales commencing from the FPSO in Q3. We are very pleased how well the FPSO refurbishment went and that it was completed within the initial timeline expected. The refurbishment was undertaken to extend the life of the vessel and to increase its capacity as we begin a significant development program at Baobab later this year.

The program includes four producers, two or three water injectors, and two workovers, providing potential meaningful additions to production from the main Baobab field, where we have a ten-year extension of the license to 2038. The current drilling plan on Baobab is to begin drilling on a batch basis the top-hole sections of all wells. These completions will then be commenced and we expect at least one well to be on full production by year end. In February 2026, in accordance with the CI-40 PSC, VAALCO Energy, Inc. and PETROCI elected to participate in the development of the Kossipo field.

VAALCO Energy, Inc. was confirmed as operator with a 60% working interest in the Kossipo field on the CI-40 block, just eight kilometers from the Baobab field. We are now working on a field development plan using new ocean bottom node seismic data that is expected to help de-risk and enhance our evaluation and development plan. The Kossipo field was discovered in 2002 with the Kossipo-1X well and later appraised in 2019 with the Kossipo-2A well, which tested at over 7 thousand 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.

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

So in less than two years, we have established a sizable position in Côte d’Ivoire with considerable upside potential. We are genuinely excited about the prospectivity in Côte d’Ivoire and its ability to help us achieve our production growth targets. Moving to Gabon. In 2025, we began our Phase 3 drilling program with the drilling of two pilot wells in the Etame field. Based on the pilot well results, we proceeded with drilling the Etame 15H-8 development well on the 1V block of Etame in December 2025. This well came online in late February at about 2 thousand gross barrels of oil per day, so our Q1 production results only had one month of production from this well.

The rig remained on the Etame platform to drill an exploration prospect in West Etame. While this well encountered 10 meters of high-quality Gamba sands, the target zone was water-bearing and not commercial. The lower portion of the well was plugged and abandoned, but the wellbore was utilized and we sidetracked the upper portion of the well to drill the Etame 14H-8 development well in the main fault block of Etame that was de-risked from the results of the earlier pilot wells. In late April, the Etame 14H-8 was brought online with an impressive initial rate of around 4.85 thousand gross barrels of oil per day.

This well encountered 325 meters of lateral net pay in high-quality Gamba sands in an attic position within the main fault block at Etame. Our second quarter production at Gabon should be enhanced by two months of production from this very successful well. After completing the program at the Etame platform, we moved the rig to the Avouma platform where we are drilling a development well and a workover well to enhance production, lower cost, and potentially add reserves. We also plan another two wells at South Tchibala platform following the completion of the program at Avouma.

We expect that development well at Avouma to be completed later this quarter and we plan to announce the results to the market when that happens. Regarding our exploration blocks in Gabon, the Nyonie Marine and Gnondo Marine, we are working with our partners 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. Processing of the seismic data has begun with early products expected to begin arriving later this year. Given the proximity of these blocks to prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks.

Turning to Egypt, for the past year, we had contracted a rig and drilled about 20 wells across a drilling campaign that helped to increase production year-over-year in 2025. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. In conjunction with our drilling program, we also continued performing production optimizations, workovers, and recompletions that have significantly improved our production performance. While we wrapped up the drilling program in 2025, given the strong results, we have added a six-well drilling program in Egypt that is commencing in Q2, which should help increase production in Q3.

We have not increased our 2026 CapEx guidance for the cost of these wells as the range we provided in March can comfortably include these new wells. We also plan optimizations, workovers, and recompletions in 2026 that are focused on production enhancement. Egypt production remains strong and we continue to invest to drill development wells and continue to delineate opportunities in Ghazalat that could open additional prospects in the future. Turning to Equatorial Guinea. In March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. Last summer, we began our front-end engineering design, or FEED, study.

The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risk and challenges from the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development versus the original shelf development, which would also significantly simplify drilling operations and well design, and this evaluation is currently underway. We are expecting to proceed with our plans to develop, operate, and begin producing from the discovery in Block P offshore. We are targeting Venus FID in 2026. In closing, we have an outstanding diversified portfolio that we believe has significant upside opportunities. We remain focused on growing production, reserves, and value for our shareholders.

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

Ronald Y. 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 guidance. As George discussed, operationally, we are performing very well. But the first quarter was an inflection point for us financially. I want to begin by highlighting the multiple factors that impacted our Q1 financial results, including the timing and number of liftings in Gabon, exploration expense, and both realized and unrealized derivative losses.

I want to point out that in the previous conference call, and in our Q1 guidance, we discussed the reduced sales volumes expected in Gabon due to the sole lift being a government lift. As I 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. We also sold the Canadian assets in February, and as a result, only had a portion of production and sales from those assets in Q1. Additionally, as George discussed, Côte d’Ivoire remained offline for the FPSO refurbishment; production should resume by the end of the second quarter.

Despite all these factors, our Q1 sales and production were both slightly above the midpoint of our guidance. We forecasted that Q1 sales would be quite a bit below production; by the midpoint of the full-year, production and sales guidance are much more in line, which means sales will likely exceed production in future quarters. This can be seen in our Q2 guidance. While Q1 sales had no partner liftings in Gabon, we expect two partner liftings in Q2, which is expected to significantly increase our sales revenue and ultimately our adjusted EBITDAX. Another major factor impacting earnings and the expenses in the first quarter was the $22.4 million in exploration expense.

This was driven by the cost of an exploration well at West Etame offshore Gabon that was determined to be unsuccessful and additional seismic costs at the Nyonie and Gnondo blocks in Gabon. In the previous call, we also discussed the forecasted exploration expense and Q1 actually came in below the guidance range of $27 million to $32 million. Nearly all of our expected annual exploration expense came in Q1. Turning to hedging. In 2025, we entered into a new reserve-based lending facility to help provide VAALCO Energy, Inc. with short-term funding to supplement our internal cash flow generation, as we have multiple large capital projects underway across our portfolio.

Over the past year, we have been talking about the more programmatic hedging program that will be more consistent over a rolling time horizon. We are looking to mitigate risk and protect the cash flow needed for our capital investments and shareholder distributions through the ongoing hedging program. Prior to the Iran conflict, the hedging program consisting primarily of collars allowed us to protect our downside risk and lock in a range of prices that allowed us to generate strong cash flow.

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

Our full quarterly hedge positions are disclosed in the earnings release. Turning now to the first quarter results, we reported a net loss of $93.7 million in Q1 2026, which was driven by $71 million in derivative losses, of which $56 million represents unrealized book losses, and a $22.4 million exploration expense. While most of our expected exploration expense for 2026 occurred in Q1, with the uncertainty in macro events and oil pricing our realized and unrealized derivative losses could continue to impact earnings in the coming quarters. We also generated adjusted EBITDAX of $11.6 million, which included no partner liftings in Gabon and no sales in Côte d’Ivoire.

Q2 2026 is expected to be materially improved due to the two planned partner liftings in Gabon, and Q3 2026 sales are expected to include Côte d’Ivoire. With the FPSO expected to be fully operational in June, we are forecasting some production in Côte d’Ivoire in Q2, but there will not be any liftings until Q3. Production in Q1 was 15.11 thousand NRI BOE per day or 19.88 thousand working interest BOE per day, both above the midpoint of VAALCO Energy, Inc.’s guidance. As I discussed earlier, sales of 12.16 thousand NRI BOE per day for Q1 were slightly above the midpoint of guidance but quite a bit lower than production.

Turning to costs, with no partner liftings in Gabon, our production costs for Q1 on an absolute basis were quite a bit lower than in Q4 2025 and were well below the midpoint of guidance both on an absolute basis and on a per-barrel basis. Our focus remains on keeping our costs low to enable us to maximize margins and increase cash flow. But with higher fuel and service costs driven by the Iran conflict, we may see some expenses increase in the near term. Looking at G&A, our cash G&A totaled $6.9 million, which was below the low end of guidance.

Moving to taxes, in the first quarter, we reported an income tax expense of $4.3 million, which was comprised of a $14.9 million current tax expense offset by a deferred tax benefit of $10.6 million. Income tax expense included a $2.9 million unfavorable oil price adjustment as a result of the change in value of the government's allocation of profit oil between the time it was produced and its present mark-to-market liability. Turning now to the balance sheet and cash flow statement, in Q1, we invested $78.1 million on a cash basis and $73.3 million on an accrual basis in net capital expenditures.

This was primarily related to new wells drilled as part of the drilling campaign offshore Gabon, as well as expenditures associated with the refurbishment and reconnection activities of the FPSO in Côte d’Ivoire. Keep in mind, we wrote off the cost of the unsuccessful West Etame well, so that cost is not in CapEx. Unrestricted cash at the end of the first quarter was $48 million. In the first quarter, to help fund our capital programs, we did draw $92 million against the company's reserve-based lending facility. In April, the aggregate borrowing base under the 2025 RBL facility increased to $300 million. We now have $152 million drawn on the credit facility and net debt of $104 million.

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

We will continue to work with the Egyptian General Petroleum Corporation to maintain a strong relationship and keep our receivables current. In Q1 2026, VAALCO Energy, Inc. paid another quarterly cash dividend of $0.0625 per common share, or $6.7 million. We also announced the second quarter dividend payment, which will be paid in June. Let me now turn to guidance, where I will give you some key highlights and updates. As I mentioned earlier, guidance for the remainder of 2026 has no contribution from the Canadian assets that were sold in February, and we are forecasting the Baobab field in Côte d’Ivoire coming back online in June with sales resuming in Q3.

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

For the total company, we are forecasting Q2 2026 production to be between 21.6 thousand and 23.8 thousand working interest BOE per day and between 16.8 thousand and 18.7 thousand NRI BOE per day. This is a significant increase over Q1 production. We expect our second quarter 2026 NRI sales volumes to range between 16.8 thousand and 18.3 thousand BOE per day. We expect our absolute production cost to be higher in the second quarter, in line with the additional sales volume, and on a per-BOE basis to be in the range of $26 to $31 per NRI BOE.

This is slightly higher than Q1, as we are expecting some cost increases primarily related to fuel costs and reflects a higher mix of West African barrels versus North African barrels that dominated the mix in Q1. For our exploration expense, we are forecasting a range of between $2 million and $3 million for Q2, a 90% reduction compared to the first quarter. We expect cash G&A to be in the range of $7 million to $9 million and our annual G&A guidance remains the same. Finally, looking at CapEx, our Q1 spend was below the guidance range, but we believe this is primarily due to timing.

Our Q2 2026 capital spend is projected to be between $110 million and $130 million as we continue the drilling campaign in Gabon, we complete the FPSO refurbishment, and begin drilling additional wells in Egypt. George outlined the multiple programs across our assets, as we believe that our efforts in 2025 and 2026 are building the foundation for another step change in production in the future. Our second quarter guidance includes about $6 million in capitalized interest, all of which relates to our large capital investment program this year. Even though we are adding a drilling rig in Egypt and increasing our 2026 production and sales volumes, our full-year capital guidance for 2026 remains unchanged.

In closing, while Q1 results were impacted by several factors, we are optimistic about improvement in Q2 and for the remainder of 2026 as we expect to continue to grow production and sales volumes. We believe we remain well positioned to continue executing on our strategy of growing production and reserves while adding meaningful value. We have a long track record of successfully delivering operational results that meet or exceed expectations. We have achieved many things these past few years and 2026 has started with strong operational successes. We have delivered in the past and we 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, Ron. Our second quarter is off to a strong start with the drilling success in Gabon and the FPSO at Côte d’Ivoire back on location with production expected to restart at Baobab in June. In the first quarter, we rationalized our portfolio by selling the Canadian operations and added high-upside opportunities at Kossipo in Côte d’Ivoire. Looking across our asset base, we are executing on several projects across our expanded portfolio. In Gabon, we have an extensive drilling campaign underway and the rig is now in Avouma drilling wells and looking to do workovers that should add reserves and production.

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

In Equatorial Guinea, we have completed our initial front-end engineering and design study and confirmed the viability of the development concept and are currently evaluating alternative technical solutions which may deliver enhanced economic value. Our ability to remain focused on successfully executing our strategy is key to growing the company profitably over the remainder of the decade. We have successfully delivered strong operational and financial results for the past several years, where we have met or exceeded guidance on a quarterly basis, and we believe that we can continue to meet or exceed our guidance numbers in Q2 and beyond. There are numerous macro events that we cannot control.

The things that we can control, like operating efficiently, investing prudently, and maximizing our production, will help us deliver the forecasted growth and profitability for our shareholders and partners. The timing of the new wells in our Gabon program recently coming online and the expected restart of Côte d’Ivoire later this quarter are certainly very well timed with the increase we are seeing in oil prices. Our entire organization is actively working to deliver strong results that will continue to help fund our capital programs while also returning value to our shareholders through a top quartile dividend.

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

Operator: We will now begin the question and answer session. If you are using a speakerphone, please pick up your handset before pressing the keys. Our first question will come from Stephane Foucaud with Auctus Advisors. Please go ahead.

Stephane Foucaud: Yes. Morning or afternoon, gents. Thanks for taking my question. My question is really around what we are hearing on those oil premiums in the market versus Brent. I heard recently that some lifting in Nigeria was sold at a $15 premium to dated Brent, which is already at a premium on the M+1 prices. So I was wondering, is that what you see across your portfolio in Gabon and Egypt? And then related to that, some of the production you have is hedged. But I assume that this hedging is around Brent, so that still allows you to capture, even on that hedged production, any potential premium. If you could confirm if my understanding is right. Thank you.

Ronald Y. Bain: Hi, Stephane, it is Ron. Yes, you are correct. We saw at times a difference between the screen price and what we saw in dated Brent. We had two liftings that are coming up; I can talk to them—April and May—and on both occasions we are seeing about a $4 premium to dated Brent for our crude. So yes, we are seeing a premium for West African barrels at this point in time. Egypt is a more difficult one because it is domestically sold, but obviously the listed price in relation to that, that we are marked over from EGPC, is getting closer to dated Brent.

So not necessarily seeing the premium develop there per se, but we certainly see it on the West African barrels. And it is obviously far too soon on Côte d’Ivoire; we will not have a lift in Côte d’Ivoire until August.

Stephane Foucaud: Thank you. And with regards to the hedging, my question was that I assume the financial hedging is based on Brent. Do you because it is on dated Brent?

Ronald Y. Bain: You are quite right. Any premium to that will be above what we have our hedges in place at.

Stephane Foucaud: Okay. That is great. Thank you very much.

Operator: Our next question will come from Jeffrey Woolf Robertson with Water Tower Research. Please go ahead.

Jeffrey Woolf Robertson: Thank you. Good morning. Ron, could you share any additional color on the lifting schedules in Gabon and Côte d’Ivoire beyond the second quarter?

Ronald Y. Bain: We can certainly share in the second quarter. We have got two confirmed liftings in Gabon. We are working with the operator in CNR for Baobab, and we likely see a lifting there in the August time period. We have basically stated we will have one every other month in Gabon between now and the end of the year. And as we stated previously, we do not foresee another GOC lift this year; it is all contractor party lifts. So hopefully that helps you with your modeling there.

Jeffrey Woolf Robertson: And, George, at Kossipo, if you get the field development plan submitted before year end, what will that do to VAALCO Energy, Inc.’s ability to shift reserves from one category to another?

Ronald Y. Bain: Yes. If we get the FDP in place before year end, which is our commitment to the DGH in Côte d’Ivoire, the categorization of the 102 million barrels equivalent that is currently sitting in 2C would move to a 2P categorization within our NSAI report for year end. So that is definitely our focus. That would add to our 2P reserve books somewhere in the region of just north of 60 million barrels.

Operator: Thank you. Our next question will come from Charlie Sharp with Canaccord. Please go ahead.

Charlie Sharp: Yes. Thanks for taking my question. Just another bit of a follow-up, if I may, on liftings—and that has been very helpful in terms of the timing of those liftings. I guess, can you remind me what the typical lifting size is in Gabon? Or what the anticipated typical lifting size would be on Baobab? And also, just on your production guidance for Côte d’Ivoire, does your guidance capture any potential flush production, or would that be potentially on top of guidance? Thank you.

Ronald Y. Bain: I will start with the liftings then, Charlie. Typically, in the past in Gabon, we have lifted parcel sizes of 650 thousand gross, but as of late we have tried to maximize that out to 900 thousand. Obviously, from an economics point of view on the freight, it is more beneficial for us. So we are planning 900 thousand gross lifts. In Côte d’Ivoire, we generally plan 650 thousand lifts; we are working with the operator there to try and encourage higher lifts than that. The vessel has come back in very good shape, and there is no reason in my mind why we cannot be looking at 900 thousand to 950 thousand lifts.

George Maxwell: I will add to what Ron said there, Charlie. One of the reasons we were with the operator down at 650 thousand is that their initial plan when the vessel came back onstream was not to use the wing tanks. That plan has subsequently been changed and we are just finalizing some remedial work on-site on the wing tanks right now to make sure we have that additional storage. That means that, where before we had perhaps used those partly for ballast, they now can be used for storage capacity that starts to increase the argument around the higher liftings from Baobab.

Ronald Y. Bain: With regard to the guidance, of course, we work closely with the operator when it comes down to the production forecast. We have our own simulation models that we work on for the Baobab field and where we see the performance.

George Maxwell: You are absolutely correct that with a field shut in for some 14 months, we would expect to see flush production. We have kept all the anticipated flush production upside in reserve relative to our guidance. There are really two reasons for that. One, we are confident in the history match in our model that what we are seeing indicatively of a kick-start in production will be achieved, but we will hold that in reserve right now. The second reason is, unlike Etame, there is not a natural pressure support inside the Baobab field; it requires water injection in order to sweep that oil up to the drainage points.

So the water injection has also been shut down during this period. On the startup sequence, we would expect the water injection to begin and we do expect to see first production, but we have kept that in reserve at the moment.

Charlie Sharp: That is very helpful. Thank you.

Operator: Our next question will come from Christopher Courtenay Wheaton with Stifel. Please go ahead.

Christopher Courtenay Wheaton: Thanks very much. Two questions, if I may. Firstly, Ron, a question for you on working capital, if I may. I was surprised at the magnitude of the working capital outflow in the first quarter, particularly when my reading of the accounts is that, when you look at the difference between sales and production volumes, the Gabon cargo to pay the government taxes is already taken out of the revenue line. So I wonder if you could help unpick that for me, because it feels like I have double counted somewhere, or there has been double counting somewhere of both the Gabon tax revenue and also working capital outflow. And my second question was for George on Kossipo.

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

Ronald Y. Bain: Chris, it is Ron. I will go first on working capital. On working capital in relation to the tax position, when we accrue the barrels that are on the balance sheet, it is a liability for foreign taxes payable. When we settle those, effectively you are moving the working capital because there is an outflow of cash as you take those barrels off and settle them against that liability. That did happen in Q1. Also, our accounts payable came down a bit as we settled, along with CNR, a number of the bills on MV10 when it sailed out to Dubai and came back into African waters. So there was a movement in payables there as those bills were settled.

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

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

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

Christopher Courtenay Wheaton: That is a really helpful explanation there, George. Thanks very much indeed.

George Maxwell: Thanks, Chris.

Operator: Our next question will come from William Dezellem with Tieton Capital. Please go ahead.

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

Ronald Y. Bain: There are two things there. One, as we mentioned back in March, we intimated that the upward trend on production coming out of the Egyptian campaign in December meant we had a very strong profile coming into January and February. That was a big delta in our upside. Also, because of the performance, particularly around the final wells in the Egyptian campaign, it really led towards the acceleration of the campaign for 2026, pulling it forward from a late Q3/Q4 prospectivity that we had in a contingent plan to a firm program coming into May.

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

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

George Maxwell: Yes and no is the answer to that. It is worth reminding everyone we have been drilling and producing out of Etame for some 24 years now, so it is a very mature field. When we talk about the targeted drilling that we are going for, we talked about the concept of going after attic oil. What that actually means is we are looking at the positions where the existing drainage points are down-dip of the upper parts of the structure and we are trying to place these wells at the very top part of the structure to capture that additional oil that has not been swept by previous wells.

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

Ronald Y. Bain: Bill, I will just add a little bit more color to what George said there. As you saw, we increased the production and sales guidance from our Q4 call, and that is primarily with a view on that main fault block well, which came in very well, as well as the continued Egyptian success that we have got. So that is where the rise in the production and the sales is on the full-year guidance.

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

George Maxwell: Thanks, Bill.

Operator: Our next question is a follow-up from Stephane Foucaud with Auctus Advisors. Please go ahead.

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

Operator: Our next question is a follow-up from Jeffrey Woolf Robertson with Water Tower Research. Please go ahead.

Jeffrey Woolf Robertson: Thanks. George, at Nyonie and also at your two blocks in Gabon, what is the earliest you might expect to see wells drilled there if you continue down that path?

George Maxwell: On these blocks, if you recall, when we acquired these along with BW Energy and Panoro, the commitment position on these blocks was basically seismic acquisition, processing, interpretation, and a single well commitment. Had we been a little bit ahead of the game, we could have thought of tagging on that single well commitment at the end of this campaign in Gabon. We are definitely not going to be there because the acquisition just completed in mid-January and it is out for processing and interpretation. We are not expecting hot-shot data probably into Q3, maybe as late as Q4, for the evaluation.

As has been announced by BW Energy, they have picked up a rig to commence a program later this year in Gabon, and that program for them, I believe, runs through mid-to-end 2027. There is an opportunity that the commitment well, subject to interpretation and identification of a targeted location, could come in late 2027, early 2028, at the back end of that program. Failing that, it is then going to be down to looking at the next opportunity for a rig to be in the area to meet that commitment on the drilling program.

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

George Maxwell: It is unlikely to slip into 2027. It depends on two key things. One, the location of the well. You have to look backwards into VAALCO Energy, Inc.’s history, and you look backwards and these blocks that have been reassigned to us and our partners are areas that VAALCO Energy, Inc. previously held back in the early teens. So we do have an understanding of the prospectivity of that block, and that is why we were quite comfortable to come back in a partnership because we do see a degree of prospectivity there.

As to when and where that well will ultimately be drilled is down to, one, the location of the well and its proximity to infrastructure, and the closer to our infrastructure or their infrastructure obviously makes it more exciting for us to pull that forward because it is a much closer monetization point. So that is really what is going to be the driver—how exciting the prospects are that we find and the location of these prospects to existing infrastructure. The closer they are, the more keen we would be to drill them. It is unlikely in my mind, but you never say never, that it would fall into 2027; there is that slight possibility.

Operator: Thank you. Our next question will come from James Wilen with Wilen Management. Please go ahead.

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

Ronald Y. Bain: Jamie, it is Ron. Guidance at the moment has an exit rate of between 25,000 and 27,000 barrels. We will continue to look at that with the Gabon drilling successes as we go forward. In Côte d’Ivoire, we have previously stated we go into batch drilling there and we only see one of those wells completing, and it will be very late in the year, so it will come in for one month. If there is movement there, there is a possibility for that exit rate to be higher than that. But at this point in time, we are guiding an exit rate of between 25,000 and 27,000.

George Maxwell: The only thing I would add to that, Jamie, is, as I said earlier in the call, there are all kinds of possibilities of flush production coming on in Côte d’Ivoire when we start up. That is currently not within our guidance.

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

Ronald Y. Bain: I cannot give you specifics on free cash flow that is not taxable. What I can say, Jamie, is that you have been in the stock for some considerable time, so you know the history here. In relation to the cost pools building up, we basically see for Gabon, as I said, that we see no other GOC state lift this year. I cannot see a state lift now—and my team cannot see a state lift now—until Q1 2027 based on the volumetrics. So again, there is not a cash tax liability in relation to that.

We also foresee, with the spend that we have got both for the Baobab and the drilling campaign in Côte d’Ivoire, that we will maximize that cost pool for about a two-year period, but it really depends on oil price. If oil prices stay at this current level of around $100, we will burn through those cost pools quicker. That is the same case with Gabon. It is great that we will have incremental free cash flow from the pricing; it also means that we will burn through it, but we will not have that tax expense. You will crystallize that benefit to the company quicker than our models predict at the moment, which have the forward curve in there.

James Wilen: Not a bad thing at all. Thanks, fellas.

Ronald Y. Bain: Thank you.

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

George Maxwell: Thank you, operator. I would like to thank everyone participating in today's call. We have had a considerable amount of activity and, as Jamie mentioned in his question, we have a lot of moving parts. We have a lot of cash catalysts that are happening throughout 2026. By the time we get to midyear, we will have three drilling campaigns fully active in our assets, drilling wells and enhancing production—catalysts to generating cash flow. We have a very, very busy year ahead, and that busy year is building both the profiles and the opportunity for significant steps up in production in early 2027.

I do not want to look that far ahead because we only need to look as far ahead as Q2, when we start to see the increase in crude oil sales coming from liftings, and those liftings are increasing even more with the additional production that we are taking in Gabon from the drilling campaign and the restart of the Baobab field. We have seen Egypt operating very successfully from the last campaign in Q4 2025. We made the decision to accelerate the program in 2026 to further enhance those opportunities. We did not talk much about Equatorial Guinea, but I will highlight again we are targeting FID in Equatorial Guinea this year.

We are building to continue that step change in production going into 2027 and 2028. Thank you. I look forward to talking to you in the Q2 call in August.

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

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