What changed in this filing

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Item 5. Market for Registrant’s Common Equity

2026-03-16 compared with 2025-03-17 · 243 added, 210 removed, 240 unchanged (65% of the section changed)

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This number does not include beneficial or other owners for whom common stock may be held in “street” names.

On February 14, 2023, we announced that our board of directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter commencing in the first quarter of 2023 and continued throughout the years 2023 and 2024.

Our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter commencing in the first quarter of 2023.

The following table is a schedule of our dividends paid during 2025:

Dividend Payment Date Amount per common share Record Date

March 28, 2024 $ 0.0625 March 8, 2024

March 28, 2025 $0.0625 February 28, 2025

June 27, 2025 $0.0625 May 23, 2025

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The share buyback program was completed on March 12, 2024.

The below table shows the repurchases of equity securities related to the share repurchase program during the fiscal year ended December 31, 2024:

Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Programs Maximum Amount that May Yet Be Used to Purchase Shares Under the Program

January 1, 2024 - January 31, 2024 446,366 $ 4.48 446,366 $ 3,516,205

February 1, 2024 - February 29, 2024 474,100 $ 4.22 474,100 $ 1,516,630

March 1, 2024 - March 12, 2024 347,137 $ 4.33 347,137 $ —

Total 1,267,603 1,267,603

Management ’ s Discussion and Analysis of Financial Condition and Results of Operations

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We are an independent energy company headquartered in Houston, Texas engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

We have a diversified African-focused asset portfolio in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea and Nigeria, as well as producing properties in Canada.

We have a diversified African-focused portfolio of production, development and exploration assets located in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea, Nigeria, as well as, prior to the Canada Asset Divestment, producing properties in Canada.

For further discussion of our five operating segments see “Item 1.

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We believe that our quality portfolio, strong management and technical expertise specific to the markets in which we operate, and our ongoing focus on maintaining a competitive cost structure and disciplined capital allocation framework position us to achieve our business strategy and navigate a variety of commodity price environments.

Over the past years,

we have delivered on our focused strategy and believe we will continue to do so with the organic growth programs across our diversified portfolio over the coming years.

Over the past years, we have delivered on our focused strategy and believe we will continue to do so with the organic growth programs across our diversified portfolio over the coming years.

Recent Developments and Outlook

2025 Acquisition

On April 30, 2024, we completed the acquisition of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden whereby we acquired all of the issued shares in the capital of Svenska and Svenska became a direct, wholly-owned subsidiary of the Company (“Svenska Acquisition”) for a net adjusted purchase price of $40.2 million.

The purchase price was funded with the Company's cash on hand.

As a result of the Svenska Acquisition, we acquired Svenska’s primary asset:

a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa.

We also acquired a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.

In March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire as the operator with a 70% working interest and a 100% paying interest though a commercial carry arrangement with two other parties inclusive of the State Oil Company.

The CI-705 block is located in the Tano basin, west of the Company’s CI-40 Block, where the Baobab and Kossipo oil fields are located.

The total amount of acquisition costs for this transaction is approximately $3.0 million.

Divestment of Non-Core Assets

On February 4, 2026, the Company entered into an asset purchase agreement (the “Canada APA”) to sell all its operating assets in Canada (the “Canada Asset Divestment”) for a purchase price of $24.4 million (C$33.4 million Canadian dollars), subject to customary adjustments.

The Canada Asset Divestment closed on February 19, 2026 with an effective date of February 1, 2026 for an adjusted purchase price of $25.5 million.

The Canada Asset Divestment represents the Company’s complete exit of its Canadian oil and gas operations.

Please see Part IV, Item 15., Note 4.

Acquisitions and Divestiture and Note 20.

Subsequent Events , to the Consolidated Financial Statements for further discussion on the Canada Asset Divestment.

Capital Program

We expect our 2025 capital program to range between $270 million to $330 million, assuming normal operating conditions, that prioritizes free cash flow generation and meaningful return of capital to shareholders.

The program includes estimated spending of approximately between $115 million to $135 million for Gabon, $30 million to $40 million for Egypt, $8 million to $13 million for Canada, $1 million to $3 million for Equatorial Guinea, $115 million to $135 million for Cote d'Ivoire for oil and natural gas development and $1 million related to corporate and other capital costs.

We expect our 2026 capital program to range between $290.0 million to $360.0 million, assuming normal operating conditions, which prioritizes free cash flow generation and meaningful return of capital to shareholders.

The program includes estimated spending of approximately between $110.0 million to $135.0 million for Gabon, $9.0 million to $12.0 million for Egypt, $0.5 million to $1.5 million for Equatorial Guinea, $170.0 million to $210.0 million for Cote d'Ivoire for oil and natural gas development and $0.5 to $1.5 million related to corporate and other capital costs.

The foregoing amounts related to Etame projects in Gabon do not include amounts funded by the non-operating partners.

See further discussion below under “Capital Resources, Liquidity and Cash Requirements” for further discussion on the capital spending for each of our operating segments.

See below under

“Capital Resources, Liquidity and Cash Requirements” for further discussion on the capital spending for each of our operating segments.

Commodity Prices

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To mitigate some of the risk inherent in oil and natural gas prices, we have utilized various derivative instruments to hedge commodity price risk.

Trends and Uncertainties

Geopolitical Conflict and Other Market Forces – The Company continues to monitor geopolitical developments globally, and specifically in Europe, the Middle East, Africa, and North America, where they have the potential to impact operational continuity and market dynamics.

On October 9, 2025, Israel, Hamas, the United States and other countries in the region agreed to a framework for a ceasefire in Gaza between Israel and Hamas, which if sustained, could reduce regional instability in the Eastern Mediterranean, and improve security conditions affecting Egypt operations and related energy supply chains.

However, such ceasefire has not progressed beyond the first phase, and whether the ceasefire will be sustained or will result in a lasting de-escalation of tensions in the region is unknown.

Additionally, geopolitical tensions and localized disruptions persist in parts of West Africa, where we hold significant producing and development interests, require ongoing vigilance regarding political, economic, and security risks.

Global markets are also experiencing volatility and uncertainty connected to the United States-Israel-Iran war and U.S intervention in Venezuela.

Following the February 2026 missile strikes in Iran, there has been increased instability, including airspace closures in the Middle East, damage to airports and the de facto closure of Strait of Hormuz, a waterway that transports approximately 20% of the world’s petroleum.

The duration and impact of these ongoing armed conflicts, and the potential of these conflicts spreading to more regions is uncertain and could adversely affect the global economy, financial markets, our customers and in turn us.

Additionally, global market forces including inflation, supply chain constraints due to lingering impacts from conflicts such as the Russia-Ukraine war, and shifts in U.S.

trade policy including tariffs on energy-related goods, continue to increase costs and extend lead times for equipment and materials essential to drilling and production activities.

These factors could affect project timing, cost structures, and overall operational efficiency.

The Company also notes ongoing volatility in commodity prices driven by dynamic supply and demand fundamentals, energy transition policies, and broader macroeconomic uncertainties.

Vaalco actively manages exposure to these risks through operational flexibility, diversified sourcing, and prudent financial planning to safeguard long-term growth and value creation.

Tariffs and Global Trade Policies – In 2025, the U.S.

administration enacted sweeping trade legislation, including significant tariff increases on industrial goods, energy-related equipment, and certain critical minerals, with a stated intent to prioritize domestic manufacturing and energy security.

Global trade policy continues to evolve and the ultimate impact of recent developments with respect to U.S.

tariffs is unclear.

On February 20, 2026, the United States Supreme Court issued a ruling striking down certain tariffs previously imposed under the International Emergency Economic Powers Act (“IEEPA”).

Following the Supreme Court’s decision, the U.S.

presidential administration announced its intention to invoke other laws to collect tariffs and announced new tariffs on imports from all countries, in addition to any existing non-IEEPA tariffs.

While there is significant uncertainty as to the duration of these and any further tariffs, and the impacts these tariffs and any corresponding retaliatory tariffs will have on the oil and gas industry and on commodity prices, these tariffs, along with anticipated retaliatory measures from affected trading partners, have introduced new volatility into the global supply chain for energy infrastructure.

While we do not maintain U.S.

based production assets, our operations on the continent of Africa rely on equipment, services, and materials that are often sourced, engineered, or consolidated through the United States or through U.S.

aligned trading routes.

As a result, we may experience increased costs and longer lead times for the procurement and

delivery of drilling and production equipment, particularly if suppliers adjust pricing in response to increased duties or if we are required to diversify sourcing channels.

These impacts could affect the timing, cost structure and execution risk of certain development activities, especially in frontier offshore environments.

Additionally, the evolving global trade environment may increase compliance complexity and affect the cost efficiency of international operations.

Enhanced documentation requirements and new rules of origin associated with U.S.

trade actions could impact our ability to efficiently move materials through international logistics hubs, such as those in Houston, Texas and could necessitate additional internal resources to maintain compliance.

These complexities necessitate additional internal resources to ensure sustained compliance and efficient material flow.

The broader geopolitical trade environment, including retaliatory tariffs and ongoing trade tensions with key partners, continues to inject volatility into the global supply network, necessitating vigilant risk management and strategic sourcing to mitigate operational disruptions and cost impacts.

Enactment of the One Big Beautiful Bill Act of 2025 – On July 4, 2025, the budget reconciliation bill known as the One Big Beautiful Bill Act of 2025 (“OBBBA”) was signed into law, which includes significant changes to federal tax law and other regulatory provisions that may impact the Company.

Among other provisions, the OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017.

The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027.

The impact of provisions effective in 2025 are not material and the Company is still assessing the impact of provisions that are not yet effective.

Moreover, to the extent U.S.

policy shifts create uncertainty in bilateral relations or disrupt traditional trade partnerships, there could be indirect effects on our ability to manage risk and maintain favorable operating conditions in host countries.

While we continue to monitor the evolving regulatory and trade landscape, we cannot predict the full impact of current or future tariffs, trade restrictions or retaliatory actions on our operations, financial condition or future capital deployment decisions.

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile.

Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand.

Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC.

In addition, recent U.S.

energy policy changes that prioritize domestic production and energy security, including through tax credits and development incentives, may influence global supply dynamics and capital flows, potentially altering the competitive landscape for international assets.

ESG and Climate Change Effects – Sustainability matters continue to attract public, political, regulatory and scientific attention.

While 2025 has seen a deceleration in the adoption of sustainability-oriented regulation, particularly in the U.S., and a noticeable shift by some financial institutions away from explicitly “ESG” or “Net Zero” branded initiatives due to perceived political or reputational sensitivities, we believe the underlying trend of focusing on sustainability remains consistent.

Long-term structural pressures, including stakeholder expectations, evolving global market standards, and transition-related investment priorities, continue to support the integration of sustainability considerations into corporate strategy and capital markets.

The attention to climate change and environmental stewardship coupled with increasing government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against the oil and gas industry, including Vaalco.

For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs.

These efforts have included consideration of cap-and-trade programs, carbon taxes, voluntary efforts to reduce routine flaring, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change.

We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries.

Climate-Related Disclosures – On March 27, 2025, the SEC ended its defense of the final rules on climate-related disclosures, effectively withdrawing its support for the regulation.

The rules, which were adopted in March 2024, require publicly traded companies to disclose climate-related risks and greenhouse gas emissions.

The SEC's decision to end its defense was made after a change in administration and a shift in policy, with Acting Chairman Mark Uyeda expressing concerns about the rule's costs and intrusiveness.

While the rules remain on hold pending legal challenges, which, as of

September 2025, have been held in abeyance by the Eighth Circuit Court of Appeals until such time as the SEC reconsiders the challenged rules by notice-and-comment rulemaking or renews its defense of the rules, the SEC's withdrawal of support signals a potential shift in direction for climate disclosure regulations.

Despite this regulatory shift in the U.S., we remain committed to maintaining transparency and aligning with industry standards for similarly situated companies.

activity notwithstanding, the landscape for international climate-related financial reporting has evolved significantly.

The Task Force on Climate-related Financial Disclosures (“TCFD”), which previously served as a leading framework, ceased operations in early 2024, with its responsibilities and legacy transitioning to the International Sustainability Standards Board (ISSB).

In line with this global evolution, in June 2025, the UK government advanced its endorsement process for sustainability reporting standards by publishing exposure drafts for UK Sustainability Reporting Standards (“UK SRS”) S1 and S2, derived from the International Financial Reporting Standards (“IFRS”) S1 and S2 frameworks, and initiated a public consultation scheduled to conclude in autumn 2025.

Pending final government approval and subsequent Financial Conduct Authority (FCA) rulemaking, UK listed businesses will be subject to phased implementation starting with climate-related disclosures, excluding Scope 3 greenhouse gas emissions in the first period, transitioning to full coverage in subsequent years.

The UK approach eliminates fixed commencement dates and offers regulatory flexibility, with transitional reliefs supporting issuer compliance and a “climate-first” methodology for initial reports, ensuring a measured shift from existing TCFD requirements to the new UK SRS/IFRS-aligned disclosure regime.

UK listed entities are advised to prepare for mandatory reporting in line with IFRS S1 and S2, anticipated from accounting periods beginning in 2026, subject to the outcomes of the consultation and final government direction.

RESULTS OF OPERATIONS

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024

We reported net income for the year ended December 31, 2024 of $58.5 m illion compared to a net income of $60.4 million for the year ended December 31, 2023.

The year-over-year decrease in net income was due to higher depreciation, depletion and amortization expense, production expenses and credit losses during the year, partially offset by the increase in revenues and a bargain purchase gain related to the Svenska acquisition.

We reported a net loss for the year ended December 31, 2025 of $41.4 m illion compared to a net income of $58.5 million for the year ended December 31, 2024.

The year-over-year decrease in net income was due primarily to an impairment loss on assets held for sale for our Canada segment, a decrease in revenues partially offset by decreases in depreciation, depletion and amortization expense, credit losses and income tax expense during the current year.

Further discussion of results by significant line item follows.

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2025 2024 (Decrease)

(in thousands except per Boe information)

(in thousands except Boe and per Boe and per Bbl information)

Net crude oil, natural gas and NGLs production (MBoe) 6,043 7,296 (1,253)

Net crude oil, natural gas, and NGLs sales volume (MBoe) 6,370 7,262 (892)

Average crude oil, natural gas and NGLs sales price (per Boe) $ 56.11 $ 65.64 $ (9.53)

Average Dated Brent spot price* ($/Bbl) $ 69.14 $ 80.52 $ (11.38)

Net crude oil, natural gas, and NGLs revenue $ 359,272 $ 478,988 $ (119,716)

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Production expense 158,177 163,500 (5,323)

FPSO demobilization and other costs — 7,484 (7,484)

Exploration expense 8,914 48 8,866

Depreciation, depletion and amortization 109,978 143,034 (33,056)

Impairment loss on assets held for sale 67,224 — 67,224

General and administrative expense 33,089 29,684 3,405

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Other operating income (expense), net (2,391) 78 (2,469)

Operating income $ 136,496 $ 158,657 $ (22,161)

The revenue changes between the years ended December 31, 2024 and 2023 identified as related to changes in price or volume are shown in the table below:

(in thousands)

Price $ (1,376)

Volume 28,338

Total net revenue $ 23,922

(1) The Other in the table above includes revenues attributed to carried interests.

The table below shows net production, sales volumes and realized prices for both years.

Year Ended December 31,

Net crude oil, natural gas and NGLs production (MBoe) 7,296 6,833

Net crude oil, natural gas and NGLs sales (MBoe) 7,262 6,832

Average realized crude oil, natural gas and NGLs price ($/Boe) $ 65.64 $ 65.83

Average Dated Brent spot price* ($/Bbl) $ 80.52 $ 82.49

Operating income (loss) (20,607) 136,496 $ (157,103)

Other expense, net (5,962) 3,301 (9,263)

Income (loss) before income taxes (26,569) 139,797 (166,366)

Income tax expense 14,822 81,307 (66,485)

Net income (loss) $ (41,391) $ 58,490 $ (99,881)

* Average of daily Dated Brent spot prices posted on the U.S.

Energy Information Administration website.

Costs and Expenses 2024 2023 % Change 2024 vs.

Production expense, excluding offshore workovers ($/BOE) $ 22.50 $ 22.42 — %

Depreciation, depletion and amortization ($/BOE) $ 19.69 $ 16.88 17 %

General and administrative expense, excluding stock-based compensation ($/BOE) $ 3.48 $ 3.49 — %

Crude oil, natural gas and NGLs net revenues increased $23.9 million, or approximately 5%, during the year ended December 31, 2024 compared to the same period of 2023.

The revenue increase is primarily attributable to revenues recognized within the Cote d'Ivoire segment during the year ended December 31, 2024 that were not present in the prior period.

Crude oil, natural gas and NGLs net revenues decreased $119.7 million, or approximately 25%, during the year ended December 31, 2025 compared to the same period of 2024.

The revenue decrease is primarily attributable to lower revenues in Gabon and Côte d’Ivoire.

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year.

The Company’s Gabon segment contributed $206.0 million of revenue to the Company’s total revenue during the year ended December 31, 2024.

This compares to the $260.3 million of revenue contributed by the segment during the year ended December 31, 2023.

The decrease in revenues is primarily due to lower sales volume in Gabon.

The total sales volume in Gabon for the year ended December 31, 2024 was 2,584 MBbls or 612 MBbls lower than the sales volumes of 3,196 MBbls in the same period in 2023.

Further, we had a decrease in the Gabon average realized price per barrel received during the year ended December 31, 2024 of $78.81 per barrel (Bbl) compared to the price received in 2023 of $79.80 per Bbl.

Our share of crude oil inventory, excluding royalty barrels, was approximately 267,754 barrels and 68,766 barrels at December 31, 2024 and 2023, respectively.

The Company’s Gabon segment contributed $181.7 million of revenue to the Company’s total revenue during the year ended December 31, 2025, which is lower than the $206.0 million of revenue contributed by the segment in 2024.

The decrease in revenues is primarily due to a decrease in the Gabon average realized price per barrel received during the year ended December 31, 2025 of $65.76 per barrel (Bbl) compared to the price received in 2024 of $78.81 per Bbl.

Partially offsetting this decrease in revenues was a slightly higher sales volume for the year ended December 31, 2025 of 2,735 MBbls or 151 MBbls higher than the sales volume of 2,584 MBbls in the same period in 2024.

Our share of crude oil inventory, excluding royalty barrels, was approximately 67 MBbls and 268 MBbls at December 31, 2025 and 2024, respectively.

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC.

The Company’s Egypt segment contributed $146.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024.

This compares to the $161.0 million of revenue contributed by the segment during the year ended December 31, 2023.

The decrease in revenues was primarily due to the decrease in sales volumes during the year ended December 31, 2024 to 2,585 MBbls compared to 2,771 MBbls during the same period in 2023.

The average realized price received in Egypt was $56.47 per Bbl during the year ended December 31, 2024, which was also lower compared to the $58.11 per barrel received in 2023.

At December 31, 2024, the Company’s Egypt segment had zero barrels in oil inventory.

Crude oil sales in Canada are normally sold through pipelines to a third party.

The Company’s Canadian segment contributed $32.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024.

This compares to the $33.7 million of revenue contributed by the Canada Segment during the year ended December 31, 2023.

The Company’s Egypt segment contributed $140.0 million of revenue to the Company’s total revenue for the year ended December 31, 2025 compared to $146.0 million of revenue contributed by the segment in 2024.

The decrease in revenues was primarily due to a lower average realized price received in Egypt of $51.27 per Bbl during the year ended December 31, 2025, which was $5.20 lower per Bbl compared to the $56.47 per Bbl received in 2024.

This was partially offset by an increase in sales volumes during the year ended December 31, 2025 to 2,730 MBbls compared to 2,585 MBbls during the same period in 2024.

The Company’s Egypt segment had no oil inventory at December 31, 2025.

Prior to the Canada Asset Divestment, crude oil sales in Canada were normally sold through pipelines to a third party.

The Company’s Canadian segment contributed $19.2 million of revenue to the Company’s total revenue for the year ended December 31, 2025, a decrease from the $32.0 million of revenue contributed by the Canada Segment in 2024.

The decrease in revenues is due to the lower average realized sales price received during the year ended December 31, 2025 of $28.74 per MBoe or a decrease of $8.03 per Boe from the $36.77 per Boe received during the same period in 2024.

The decrease in the average realized price was offset by the increase in sales volumes during the same period.

In Canada, the total sales volumes for the year ended December 31, 2024 was 870 MBoe or 5 MBoe higher than the 865 MBoe sold during the year ended December 31, 2023.

In addition, there was a decrease in total sales volumes for the year ended December 31, 2025 to 667 MBoe from the 870 MBoe sold during the same period in 2024 which contributed to the decrease in revenues.

The Company’s Canadian segment had no oil inventory at December 31, 2025.

Cote d'Ivoire

Crude oil sales in Cote d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world.

The Company's Cote d’Ivoire Segment contributed $95.1 million of revenue to the Company’s total revenue during the year ended December 31, 2024.

Total sales volumes in Cote d'Ivoire for the year ended December 31, 2024 was 1,223 MBbls and the average realized sales price received was $77.74 per barrel.

Production expenses increased $10.3 million , or approximately 7%, to $163.5 million in the year ended December 31, 2024 compared to the same period of 2023.

The increase in production expense was primarily driven by the crude oil inventory acquired in the Svenska Acquisition that was recorded at fair value upon acquisition and lower of cost or net realizable value in subsequent periods.

In addition, VAALCO has seen inflationary pressure on personnel and contractor

In February 2024, the government in Gabon enacted new regulation which has resulted in an increase to withholding taxes on foreign supplied goods and services.

On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 2024 decreased to $22.48 per barrel from the prior year of $22.59 per barrel primarily as a result of higher production volumes for the current period.

FPSO demobilization costs decreased $7.5 million, or 100% , to zero in the year ended December 31, 2024 compared to the same period of 2023.

In 2023, it was determined that there was additional normally occurring radioactive material (NORMs) waste than anticipated connected to the FPSO from the Contractors' usage.

As such, VAALCO and JOA partners incurred an additional $7.5 million (net to VAALCO) in decommissioning fees, which was reported as a separate line item on the income statement.

These costs were incurred to retire the FPSO as we transitioned the Etame block to the FSO.

Exploration expen se s decreased $1.9 mi llion, or approximately 98%, in the year ended December 31, 2024 compared to the same period of 2023 due primarily to the abandonment of the Egyptian East Arta - 54 appraisal well and the abandonment of the NWG-5C1 appraisal well in 2023.

Depreciation, depletion and amortization increased $27.7 million, or approximately 24%, in the year ended December 31, 2024 compared to the same period of 2023.

The increase in depreciation, depletion and amortization expense is due primarily to the addition of Cote d'Ivoire related to the Svenska Acquisition partially offset by lower depletable costs in Gabon, Egypt, and Canada.

General and administrative expenses increased $5.8 million, or approximately 25%, in the year ended December 31, 2024 compared to the same period of 2023.

The increase in general and administrative expenses is primarily due to professional fees, accounting and legal services, and salaries and wages.

Credit loss and other allowances - Credit loss and other expense increased $11.2 million, or approximately 228%, in the year ended December 31, 2024 compared to the same period of 2023.

The increase in credit losses and other for the year ended December 31, 2024, is primarily attributable to the receivables with EGPC regarding the settlement of these receivables owed to the Company.

During the year ended December 31, 2023, the decrease in credit loss and other allowances was primarily due to two credit loss and other allowance reversals in 2023.

These two reversals were partially offset by a credit loss and other allowance adjustment in Egypt.

Crude oil sales in Côte d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world.

As previously noted, the FPSO ceased production in January 2025 to undergo a planned dry dock refurbishment.

The refurbishment work was completed in February 2026 and the Baobab FPSO has commenced its mobilization back to Cote d’Ivoire.

The FPSO is expected to return to service during the fourth quarter of 2026.

The Company's Côte d’Ivoire segment contributed $18.4 million of revenue to the Company’s total revenue for the year ended December 31, 2025 or $76.7 million lower than the $95.1 million of revenue contributed by the segment in 2024.

The decrease in revenues was primarily due to the decrease in sales volumes during the year ended December 31, 2025 to 238 MBbls compared to 1,223 MBbls during the same period in 2024.

The average realized price received in Côte d’Ivoire was $77.36 per Bbl during the year ended December 31, 2025, which was also slightly lower compared to the $77.74 per Bbl received in 2024.

The Company’s Côte d’Ivoire segment had no oil inventory at December 31, 2025.

Production expenses decreased $5.3 million , or approximately 3%, to $158.2 million in the year ended December 31, 2025 compared to the same period of 2024.

The decrease in production expense was primarily driven by a reduction in production expenses in our Côte d’Ivoire segment partially offset by an increase in expenses in our Gabon segment.

On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 2025 increased to $24.78 per barrel from $22.48 per barrel for the year ended December 31, 2024.

The increase in production cost per barrel is primarily due to a 17% decrease in production volumes compared to the prior year.

Exploration expen se s for the y ear ended December 31, 2025 of $8.9 mi llion was attributable to the purchase of seismic data to be used in Block 705 in Cote d’Ivoire, the costs associated with Blocks G and H in Gabon and the costs associated with the Egypt exploration well in South Ghazalat determined to be not commercially viable.

Exploration costs incurred during the same period in 2024 was minimal.

Depreciation, depletion and amortization decreased $33.1 million, or approximately 23%, to $110.0 million in the year ended December 31, 2025 compared to the same period of 2024.

The decrease in depreciation, depletion and amortization expense is due primarily to no production in Côte d’Ivoire since January 2025 when the FPSO went offline.

General and administrative expenses increased $3.4 million, or approximately 11%, to $33.1 million in the year ended December 31, 2025 compared to the same period of 2024.

The increase in general and administrative expenses is primarily due to an increase in stock based compensation, salaries and wages, and professional service fees.

Credit loss and other allowances - Credit loss and other expense decreased $6.2 million, or approximately 98%, to $0.1 million in the year ended December 31, 2025 compared to the same period of 2024.

The credit losses and other for the year ended December 31, 2024 was primarily attributable to the higher allowance calculated during 2024 related to the Egypt

Backdated Receivables, defined in Part IV, Item 15., Note 11.

Commitments and Contingencies to the Consolidated Financial Statements.

The Backdated Receivables were settled as of March 31, 2025, while the remaining trade receivables are current and therefore it was determined that no provision was required.

Derivative instruments gain (loss), net is attributable to our commodity instruments as discussed in Part IV, Item 15., Note 9.

Derivatives and Fair Value to the Consolidated Financial Statements.

During the years ended December 31, 2024 and 2023, we recognized net realized losses of $0.5 million and $0.1 million, respectively, and unrealized losses of $0.2 million and an unrealized gain of $0.4 million, respectively, or a total net derivative losses of $0.7 million and net derivative gain of $0.2 million, respectively.

Derivative losses for 2024 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the year ended December 31, 2024.

Our derivative instruments currently cover a portion of our production through September 2025.

Interest (expense) income, net decreased $2.7 million to an expense of $3.7 million for the year ended December 31, 2024 from an expense of $6.5 million during the same period in 2023.

The decrease of net interest expense for the year ended December 31, 2024 primarily results from a decrease in our amortization of debt issue costs and commitment fees incurred on the RBL Facility partially offset by interest income.

Other (expense) income, net increased $4.9 million to an expense of $5.8 million for the year ended December 31, 2024 from an expense of $0.9 million for the year ended December 31, 2023.

Derivatives to the Consolidated Financial Statements.

During the years ended December 31, 2025 and 2024, we recognized net realized losses of less than $0.1 million and $0.5 million, respectively, and an unrealized gain of $2.9 million and an unrealized loss of $0.2 million, respectively, or a total net derivative gain of $2.9 million and a total net derivative loss of $0.7 million, respectively.

Derivative gains for 2025 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the year ended December 31, 2025.

Our derivative instruments currently cover a portion of our production through March 2027 for oil and through December 2026 for gas.

As part of our Canada Asset Divestment, the purchaser under the Canada APA assumed our hedge contracts associated with gas production volumes from our Canada operating segment.

Impairment loss on assets held for sale for the year ended December 31, 2025 of $67.2 million was attributable to recorded impairments to the carrying value of proved and unproved oil and gas properties for our Canada assets reported as held for sale.

The impairment was primarily attributable to a sustained decline in forward strip commodity prices during the period, including decreases in both crude oil and natural gas benchmark pricing.

Lower forward pricing reduced expected future net cash flows and negatively impacted market participant valuation assumptions.

As a result, estimated proceeds from the planned divestiture declined below the carrying value of the disposal group.

There were no assets held for sale as of December 31, 2024.

Interest (expense) income, net increased $4.5 million to an expense of $8.2 million for the year ended December 31, 2025 from an expense of $3.7 million during the same period in 2024.

The increase of net interest expense for the year ended December 31, 2025 primarily resulted from an increase in our amortization of debt issue costs, commitment fees incurred and interest incurred on our borrowing under the 2025 RBL Facility, partially offset by interest income.

The Company did not draw any amounts under its previous reserve-based credit facility during 2024.

Other (expense) income, net decreased $5.2 million to an expense of $0.6 million for the year ended December 31, 2025 from an expense of $5.8 million for the year ended December 31, 2024.

Other (expense) income, net normally consists of foreign currency losses as discussed in Part IV, Item 15., Note 2.

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However, for the year ended December 31, 2024, other (expense) income, net, also included $3.9 million of transaction costs associated with the Svenska Acquisition.

Income tax expense (benefit) f or the year ended December 31, 2024 was an expense of $81.3 million.

This is comprised of $98.9 million of current tax expense and a deferred tax benefit of $17.6 million.

Income tax expense for the year ended December 31, 2023 was an expense of $89.7 million.

This was comprised of $92.6 million of current tax expense and a deferred tax benefit of $2.9 million.

Income tax expense (benefit) f or the year ended December 31, 2025 was an expense of $14.8 million which includes a $13.7 million favorable oil price adjustment as a result of the change in value of the government of Gabon's allocation of Profit Oil between the time it was produced and the time it was taken in-kind.

After excluding this impact, income taxes were $28.5 million for the period.

For the year ended December 31, 2024, we recorded an income tax expense of $81.3 million which is comprised of $98.9 million of current tax expense and a deferred tax benefit of $17.6 million.

The current tax expense in both periods is primarily attributable to our operations in Gabon, Egypt, Canada and Cote d'Ivoire.

The income tax expense is higher in 2024 than income tax for the comparable 2023 period as a result of higher revenues.

The income tax expense is lower in 2025 than the income tax expense in 2024 period as a result of lower revenues.

See Part IV, Item 15., Note 7.

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During 2025, we had accrual basis expenditures attributable to operations of $236.4 million, that includes $61.7 million for Gabon, $28.8 million for Egypt, $1.6 million for Canada, $143.2 million for Cote d'Ivoire, $0.6 million for Equatorial Guinea and $0.5 million for the corporate offices, compared to $109.4 million for 2024.

Capital expenditures in 2024 were attributable to expenditures primarily related to the new wells drilled as part of the drilling campaign in Canada, the workover and drilling program in Egypt and the expenditures associated with the preparation of the FPSO dry dock project in Cote d'Ivoire.

Capital expenditures in 2023 were primarily related to the payments for the 2023 drilling campaigns in Egypt and Canada.

Capital expenditures in 2025 were attributable to expenditures primarily related to the new wells drilled as part of the drilling campaign in Egypt, the Phase Three drilling in Gabon, as well as expenditures associated with the refurbishment of the FPSO in Côte d'Ivoire.

During the same period in 2024, our cash spending primarily related to the Svenska acquisition as well as payments for the 2024 drilling campaigns in both Egypt and Canada.

Recent Operational Updates

The Company secured a drilling rig in December 2024 in conjunction with its 2025/2026 drilling program, which is planned to begin in mid-2025 to drill multiple development wells, and appraisal or exploration wells, as well as to perform workovers, with options to drill additional wells.

We are planning on multiple wells in both the Etame field and at our SEENT platform, and a re-drill and several workovers in the Ebouri field to access production and reserves that were previously shut in and removed from proved reserves due to the presence of hydrogen sulfide.

The Company focused on enhancing production in 2024 through a series of planned workovers.

The EA-55 well, drilled in October 2023, was completed and put online in January 2024.

During the year, the planned workover program for 2024 was completed for 12 wells, including the K-81 well recompletion at the start of the first quarter of 2024, which was a carry-over from our 2023 drilling activity.

The focus of the workover activities was to achieve peak production from the wells, significant improvements on the rate of production, and enhance production efficiency.

The Company deferred its 2024 drilling during the year to work up a robust drilling program.

We have contracted a rig and commenced with the drilling of two wells December 2024.

The first of the two wells was also successfully completed in December 2024, while the second well is expected to come on line in early 2025.

The Company’s Phase Three Drilling Program in Gabon commenced in the fourth quarter of 2025 with the drilling of the Etame 15H-ST1 development well in the 1V block of Etame in December 2025.

The well was completed and placed on production in January 2026 confirming expectations from the pilot well results.

Although the West Etame exploration well (ET-14P) encountered 10 meters of high quality sands, the target zone was water-bearing.

The lower portion of the well will be plugged and abandoned but the well bore 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.

Operations are expected to 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 and potentially add reserves.

In July 2025, the Company performed planned, staged shutdowns of the Gabon platforms to perform safety inspections and necessary maintenance to increase the integrity and reliability of the assets.

This is the first full field maintenance shutdown that the Company has performed since the new Floating Storage and Offloading vessel (“FSO”) was brought online in 2022.

All fields were successfully brought back online and the planned turnaround was completed on budget and with no safety or environmental incidents.

The BWE Consortium initiated its 3D seismic campaign across the Niosi and Guduma blocks in November 2025 and such campaign was completed in January 2026.

The seismic acquisition was executed and satisfies the minimum commitments under the terms of the Niosi PSC as well as to inform the decision on proceeding into the second exploration period for the Guduma Block.

The drilling campaign in Egypt began in December 2024 and continued throughout 2025.

During 2025, we drilled a total of 16 wells in the Eastern Dessert, which included 16 development wells.

In December 2025, we started drilling an additional well which was completed in January 2026.

All wells drilled in the Eastern Dessert successfully achieved their target.

Additionally, continuous well interventions, workovers and optimization activities were carried out in 2025 to enhance production levels.

We also drilled one exploration well in South Ghazalat which was later determined to be not commercially viable.

Cote d'Ivoire

As previously discussed, the FPSO will be placed in dry dock in early 2025 for planned maintenance and upgrades.

It ceased hydrocarbon production as scheduled on January 31, 2025 and the final lifting of crude oil from the FPSO took place on February 5, 2025.

The project team has commenced mobilization efforts, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO.

The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departure from the field around March 2025.

Significant development drilling is expected to begin in 2026 after the FPSO is expected to return to service with meaningful additions to production from the main Baobab field in CI-40, as well as a potential future development of the Kossipo field, which is also on the license.

We successfully drilled and completed four wells in 2024, all of which have been producing during the year.

The wells were drilled with longer 2.75 mile laterals to improve the economics of the program.

The new wells drilled resulted in a change in the production mix in Canada from about 60% liquids during the first quarter to about 75% after the wells came online with a lower gas-oil ratio.

In early November 2024, a fifth well was drilled and we plan to put the well online in early 2025.

In connection with the planned dry dock refurbishment, the Baobab FPSO ceased hydrocarbon production on January 31, 2025, with the final crude oil lifting in February 2025.

The vessel departed the field in late March 2025 for Dubai for the refurbishment work, which was completed in February 2026.

The Baobab FPSO has commenced mobilization back to Cote d’Ivoire and is expected to return to offshore Cote d’Ivoire by late March 2026, with field production expected to restart during the second quarter of 2026.

A rig has been secured for the planned development drilling program which is expected to begin during the fourth quarter of 2026 after the FPSO returns to service.

The drilling campaign is expected to bring meaningful additions to production from the main Baobab field in CI-40.

In February 2026, the Company became the operator with a 60% working interest in the Kossipo field on the CI-40 Block with a field development plan to be completed in the second half of 2026.

The CI-705 block is located in the Ivorian Basin, west of the Company’s CI-40 Block, where the Baobab and Kossipo oil fields are located.

In 2025, the Company decided to defer the drilling of additional wells in Canada based on a reassessment of capital allocation priorities across the portfolio and to ensure that investment is directed toward projects with the highest expected returns.

As discussed above, in early 2026, the Company completely exited its Canadian oil and gas operations.

Please see above under “ Divestment of Non-Core Assets ,” for further discussion on the sale of the Canada operating assets.

Equatorial Guinea

We own a 60% working interest in an undeveloped portion of Block P offshore Equatorial Guinea where we are the designated operator.

We have an existing plan of development of the Venus field discovery on Block P, which focuses on key areas of drilling evaluations, facilities design, market inquiries and metocean review.

In the second quarter of 2025, the Company completed the initial Front End Engineering and Design study that confirmed the viability of the development concept and is currently evaluating alternative technical solutions which may deliver enhanced economic value.

Commodity Price Hedging

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Please see Part IV, Item 15., Note 9.

Derivatives and Fair Value in our Consolidated Financial Statements for more information on the related hedges.

Derivatives in our Consolidated Financial Statements for more information on the related hedges.

At December 31, 2025 and 2024, we had unrestricted cash of $58.9 million and $82.6 million , respectiv ely, which as of certain dates, exceeded Federal Deposit Insurance Corporation insurance limits.

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Capital Resources, Liquidity and Cash Requirements

Our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in the Etame Marin block.

Our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities.

We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions.

Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and our 2025 RBL Facility to support our current cash requirements during the next 12 months and beyond, including the FSO charter, drilling programs, as well as transaction expenses and capital and operational costs associated with our business segments' operations.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and our 2025 RBL Facility to support our current cash requirements during the next 12 months and beyond, including the FPSO refurbishment, drilling programs, dividend payments, abandonment funding, as well as transaction expenses and capital and operational costs associated with our business segments' operations.

However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends for other similar transactions depends on operating and economic conditions, some of which are beyond our control.

If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all.

We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth

opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

Merged Concession Agreement

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2025 RBL Facility Agreement and Available Credit

For information on our RBL Facility Agreement and Available Credit, see Part IV, Item 15., Note 13.

Debt to the Consolidated Financial Statements.

For information on our 2025 Facility Agreement and available credit, see Part IV, Item 15., Note 12.

Debt and Note 20.

Subsequent Events to the Consolidated Financial Statements.

Debt to the Consolidated Financial Statements.

Cash Requirements

Our material cash requirements generally consist of the FPSO refurbishment, finance and operating leases, capital projects, dividend payments, Merged Concession Agreement and abandonment funding, each of which is discussed in further detail below.

Our material cash requirements generally consist of the FPSO refurbishment, finance and operating leases, capital projects, dividend payments and abandonment funding, each of which is discussed in further detail below.

Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block.

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The amounts paid will be reimbursed through the Cost Account and are non-refundable.

In August 2023 , a new abandonment study was completed and such study estimated abandonment costs of approximately $77.9 million ($45.9 million, net to VAALCO) on an undiscounted basis.

The new abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC.

In August 2023 , an abandonment study was completed which estimated abandonment costs of approximately $77.9 million ($45.9 million, net to Vaalco) on an undiscounted basis.

The abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC.

In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to Vaalco) abandonment funding payment associated with the FPSO retirement.

The Company received payment of $15.6 million in March 2023.

No additional activity was noted in the abandonment funding account during the remainder of 2023 and in 2024.

At December 31, 2024, the balance of the abandonment fund w as $10.7 million ($ 6.3 millio n, net to VAALCO) on an undiscounted basis.

No additional activity was noted in the abandonment funding account through the end of 2025.

At December 31, 2025, the balance of the abandonment fund w as $10.7 million ( $6.3 million, net to Vaalco) on an undiscounted basis.

The annual payments will be adjusted based on revisions in the abandonment estimate.

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Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.

Capital Projects - In December 2024, Vaalco secured a rig for the 2025/26 drilling campaign at Etame.

Vaalco is currently finalizing locations and planning for the next drilling campaign, which is expected to commence in Q3 2025.

We currently have a 10 to 15 well drilling campaign in Egypt, where we have completed the drilling of two wells.

In Canada, we continue to drill, recomplete and workover wells adding to our production base and cash flows.

Capital Projects - In December 2024, the Company secured a rig for the Phase Three drilling campaign at Etame and has spud the first infill well in December 2025.

The Phase Three drilling campaign includes several wells and workovers planned to enhance production, lower costs and potentially add reserves.

In Egypt, we anticipate to continue our drilling and completion campaign, as well as recompletion activities in 2026.

In CDI, a rig has been secured for the Phase 5 planned development drilling program, which is expected to begin during the fourth quarter of 2026 following the FPSO’s returns to service.

Leases - We are a party to several operating and financing lease arrangements, including operating leases, which may include corporate offices, drilling rigs, rental of marine vessels and helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, and equipment and vehicles used in operations.

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Leases to our Consolidated Financial Statements.

Merged Concession Agreement - On January 20, 2022, prior to the consummation of the TransGlobe Acquisition, TransGlobe announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics.

In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signing bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022.

On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million.

In accordance with the Merged Concession Agreement, we agreed to substitute the 2023, 2024 and 2025 payments and issue three $10.0 million credits against receivables owed from EGPC.

We plan to make the final annual equalization payment of $10.0 million on or before February 1, 2026.

We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the “Merged Concession Effective Date”).

Merged Concession Agreement - Under the Merged Concession Agreement, a total of $65.0 million of modernization payments were to be made to EGPC over a period of six years from February 1, 2020 (the “Merged Concession Effective Date”).

As of December 31, 2025, all modernization payments had been fully settled either through actual cash payments or through the issuance of credit against receivables owed from EGPC.

We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on the Merged Concession Effective Date.

As of December 31, 2025, the $50.0 million of financial work commitments had been delivered to EGPC.

FSO Agreements – On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement (the “Bareboat Charter”) with World Carrier to replace the existing FPSO with an FSO unit at the Etame Marin block offshore Gabon.

Pursuant to the Bareboat Charter, World Carrier will provide use of the Teli vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions.

Pursuant to the Bareboat Charter, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO.

As consideration for the performance by World Carrier of the Operator

Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Bareboat Charter) until the end of the term, with such term being the same as the term in the Bareboat Charter.

On October 19, 2022, we issued final acceptance certificate of the FSO.

On December 4, 2022, the first lifting from the FSO was successfully completed at the same time the final remaining volumes from the FPSO were removed.

FPSO Maintenance – The FPSO will be in transit to dry dock in early 2025 for planned maintenance and upgrades.

It ceased hydrocarbon production as scheduled on January 31, 2025 and the final lifting of crude oil from the FPSO concluded on February 6, 2025.

The project team mobilization efforts are on schedule and have significantly progressed, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO.

The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departure from the field around March 2025.

BWE Consortium – We are a member of the BWE Consortium with BW Energy and Panoro Energy, which was awarded the two blocks in the 12th Offshore Licensing Round in Gabon.

The BWE Consortium and the Gabonese government came to an agreement on the commercial terms in February 2024.

All parties to the BWE Consortium signed the PSC with the Gabonese Government during the fourth quarter of 2024.

Pursuant to the terms of the PSC, BW Energy will be the operator with a 37.5% working interest, and VAALCO will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners.

The two blocks, Niosi Marin Block (previously G12-13) and the Guduma Marin Block (previously H12-13), are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

The two blocks, held by the BWE Consortium and the PSCs over the blocks, are currently under negotiation with the Gabonese government.

Dividend Policy – On February 14, 2023, we announced that our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 2023 and continued throughout 2024.

FPSO Maintenance – The Baobab FPSO arrived at the shipyard in Dubai ahead of schedule in mid-May 2025 for planned maintenance and upgrades.

The FPSO refurbishment work was completed in February 2026 and the Baobab FPSO has commenced its mobilization back to Cote d’Ivoire.

The FPSO is expected to return to service in the second quarter of 2026.

BWE Consortium – We are a member of the BWE Consortium that was awarded the licenses for the Niosi Marin and the Guduma Marin exploration blocks in Gabon.

These licenses are covered by PSCs entered into with the Gabonese Government.

These PSCs will have two exploration periods totaling eight years which may be extended by an additional two more years.

During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks.

The first exploration period ends in May 2026.

In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.

Under the terms of the BWE Consortium PSC, the Company holds a 37.5% non-operating working interest in these licenses.

Dividend Policy – Our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 2023.

Payment of future dividends, if any, will be at the discretion of the Board of Directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.

Trends and Uncertainties

Geopolitical Conflict and Other Market Forces – Global conflicts, including Russia’s invasion of Ukraine, conflicts in the Middle East, and heightened tensions in the Pacific region, have significantly elevated global geopolitical tensions and security concerns.

Economic sanctions, export controls, and other trade restrictions, for instance those that the U.S.

Government and other nations implemented against Russia in light of its invasion of Ukraine or those relating to the conflict in the Middle East, could directly and indirectly continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets.

The extended war between Russia and Ukraine and increasing hostilities in the Middle East, could continue to intensify and may cause prolonged uncertainty and volatility in commodity prices.

The extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile.

Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand.

Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+.

ESG and Climate Change Effects – Sustainability matters continue to attract considerable public, regulatory and scientific attention.

In particular, we expect continued required reporting attention on climate change issues and emissions of GHG, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion) and freshwater use.

For example, in March 2024, the SEC adopted final rules under SEC Release No.

The Enhancement and Standardization of Climate-Related Disclosures for Investors, which requires registrants to provide certain climate-related information in their registration statements and annual reports.

The rules require information about a registrant’s climate-related risks that are reasonably likely to have a material impact on its business, results of operations, or financial condition.

These requirements are effective for the Company in various fiscal years, starting with its fiscal year beginning November 1, 2026.

On April 4, 2024, the SEC determined to voluntarily stay the final rules pending certain legal

The Company believes that the impact of these final rules on its consolidated financial statements and disclosures are not material.

This increased attention to climate change and environmental conservation coupled with stepped up government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against us.

For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs.

These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change.

Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG reporting requirements, including establishing and communicating short and long-term goals and targets, furthering the reduction of our carbon footprint and measurement of GHG emissions.

Sustainability remains an important topic to us, and we are in the process of developing a multi-year plan to establish and document our progress in achieving goals we set for ourselves across all areas of sustainability.

Our plans will enable us to monitor and improve matters related to ESG and climate change going forward.

For the past four years the Company has matured its reporting in line with the recommendations of the Task force on Climate-related Financial Disclosures (“TCFD”), which is recognized as the global standard in climate-related reporting.

The full TCFD report was included within the 2023 Sustainability Report (rather than in this Annual Report on Form 10-K or in the annual report which was published in connection with the annual meeting), as the 2023 Sustainability Report details environmental, social and governance matters which the TCFD report forms an important part.

The 2023 Sustainability Report is available on the Company's website, which is not incorporated by reference hereto.

Drilling Rig Commitment - The Company entered into a bareboat charter agreement (the “Bareboat Charter”) in late 2024 to charter the drilling rig for its Phase Three drilling campaign in Gabon.

Pursuant to the Bareboat Charter, the Company also entered into a service agreement with a third party for the drilling rig maintenance and operations.

The Bareboat Charter commenced with the mobilization of the drilling rig towards the Company’s first well in November 2025 and has a noncancellable period of 300 days plus five single well options.

The Bareboat Charter stipulates fixed day rates and other variable payments.

Our cash flows for the years ended December 31, 2025 and 2024 are as follows:

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Net change in operating assets and liabilities 95,404 (70,594) 165,998

Net cash provided by (used in) operating activities 113,718 223,597 (109,879)

Net cash provided by (used in) investing activities (102,119) (97,223) (4,896)

Net cash provided by operating activities 212,667 113,718 98,949

Net cash used in investing activities (255,890) (102,119) (153,771)

Net cash provided by (used in) in financing activities 12,377 (43,048) 55,425

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Net change in cash, cash equivalents and restricted cash $ (30,763) $ (31,452) $ 689

The $109.9 million decrease in net cash provided by operating activities during the year ended December 31, 2024 compared to the year ended December 31, 2023, was driven primarily by changes in operating assets and liabilities during the period.

The net decrease in changes provided by operating assets and liabilities of $111.5 million for the year ended December 31, 2024 compared to the same period of 2023 was related to a decrease in cash provided by trade receivable, Accounts with joint venture owners, net and Egypt receivables and other, net (collectively $86.1 million).

In addition, cash used by operating assets and liabilities increased due to a decrease in the accrued liabilities and other balances of $27.0 million.

Partially offsetting these changes was an increase in cash provided on a decrease in cash used in Accounts Payable of $14.9 million.

The $98.9 million increase in net cash provided by operating activities during the year ended December 31, 2025 compared to the year ended December 31, 2024, was driven primarily by changes in operating assets and liabilities during the period.

The net increase in changes provided by operating assets and liabilities of $166.0 million for the year ended December 31, 2025 compared to the same period of 2024 was related to an increase in cash provided by trade receivable and Egypt receivables and other, net (collectively $121.7 million).

In addition, cash provided by operating assets and liabilities increased due to an increase in accounts payable and accrued liabilities and other balances of $82.9 million.

Partially offsetting these changes was a decrease in cash provided on a decrease in foreign income taxes receivable (payable) of $45.1 million.

The $153.8 million increase in net cash used in investing activities during the year ended December 31, 2025 was due to the increase in cash capital spending in 2025.

In 2023 we incurred significant capital for the 2021/2022 Etame drilling campaign and the Etame field reconfiguration.

In 2025 capital spending was primarily attributable to costs associated with the development drilling programs in Egypt, as well as maintenance, project costs and long lead items for Gabon and Côte d'Ivoire.

In 2024 capital spending was primarily attributable to the costs associated with the recompletion and drilling program.

In addition, VAALCO used $40.2 million in cash for the acquisition of

Svenska which is offset by the cash received from Svenska in the amount of $41.0 million.

See Part IV, Item 15., Note 4.

Acquisitions to the Consolidated Financial Statements for further discussion of the acquisition.

Net cash used in financing activities during the year ended December 31, 2024 included $26.2 million for dividend distributions, $6.8 million for treasury stock repurchases made under our stock repurchase plan or as a result of tax withholding on options exercised and on vested restricted stock, and $10.5 million of principal payments on our finance leases partially offset by $0.4 million in proceeds from options exercised.

For the twelve months ended December 31, 2023, cash used in financing activities included $26.8 million for dividend distributions, $23.6 million for treasury stock repurchased under our stock repurchase plan, and $7.2 million of principal payments on our finance leases partially offset by $0.7 million in proceeds from options exercised.

In addition, the Company used $40.2 million in cash for the acquisition of Svenska which is offset by the cash received from Svenska in the amount of $41.0 million.

Net cash provided by financing activities during the year ended December 31, 2025 included $60.0 million in proceeds from borrowings under our new 2025 RBL Facility partially offset by $26.5 million for dividend distributions, $0.7 million for treasury stock repurchases as a result of tax withholding on options exercised and on vested restricted stock, $7.1 million for deferred financing costs related to our new 2025 RBL Facility and $13.3 million of principal payments on our finance leases.

For the year ended December 31, 2024, cash used in financing activities included $26.2 million for dividend distributions, $6.8 million for treasury stock repurchased under our stock repurchase plan, and $10.5 million of principal payments on our finance leases partially offset by $0.4 million in proceeds from options exercised.

Regulatory and Joint Interest Audits

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We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability.

We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations.

We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations and comprehensive income (loss).

To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

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The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits.

Changes in tax laws, regulations, agreements and tax treaties or our level

of operations or profitability in each jurisdiction would impact our tax liability in any given year.

We also operate in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities.

Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year.

We also operate in

foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities.

While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

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Factors considered include earnings generated in previous periods, forecasted earnings, the expiration period of carryovers, and overall economic conditions of the industry.

As of December 31, 2024, we had deferred tax assets of $266.5 million primarily attributable to Canada, Gabon and U.S.

As of December 31, 2025, we had deferred tax assets of $310.0 million primarily attributable to Canada and U.S.

basis differences in fixed assets, foreign tax credit carryforwards, and foreign net operating loss carryforwards.

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• future production rates based on historical performance and expected future operating and investment activities;

• future crude oil, natural gas and NGLs quality differentials;

• future crude oil, natural gas and NGLs differentials;

• assumed effects of regulation by governmental agencies;

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as prescribed by the Society of Petroleum Engineers.

Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI for Gabon, Egypt and Cote d'Ivoire, while GLJ evaluates our Canadian reserves.

Reserve estimates are independently evaluated at least annually by NSAI, who is our independent qualified reserves engineer.

Prior to 2025, reserves estimates for Canada were evaluated by GLJ.

Equatorial Guinea will receive a Management Case Report.

Our Board of Directors has established the Technical & Reserves Committee with the authority, responsibility and primary purpose of assisting the Board of Directors in its oversight responsibilities relating to evaluating and reporting on oil and gas reserves.

respect to oil and gas reserves and shall consult with the Audit Committee on such matters relating to oil and gas reserves which impact our financial statements.

The Technical & Reserves Committee, to the extent it deems necessary or appropriate, will oversee (i) annual review of oil and gas reserves, (ii) procedures for evaluating and reporting oil and gas producing activities, and (iii) compliance with applicable regulatory and securities laws relating to the preparation and disclosure of information with respect to oil and gas reserves and shall consult with the Audit Committee on such matters relating to oil and gas reserves which impact our financial statements.

Our senior executives and reserve engineers oversee the preparation of our crude oil, natural gas and NGLs reserves and related disclosures by our appointed independent reserve engineers.

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When a crude oil, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value.

Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved reserves.

Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved and probable reserves.

Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data.

The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows.

In addition, we considered risk adjustment factors in our fair value measurement.

The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared reserve reports evaluated by independent reserve engineers adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

Assets that are not impaired on a held-and-used basis could possibly become impaired if a decision is made to sell such assets.

That is, the assets would be impaired if they are classified as held-for-sale and the estimated proceeds from the sale, less costs to sell, are less than the assets’ associated carrying values.

For further discussion, see Part IV, Item 15., Note 4.

Acquisitions and Divestitures and Note 8.

Crude Oil, Natural Gas and NGLs Properties and Equipment, Net to the Consolidated Financial Statements.

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When undeveloped crude oil, natural gas and NGLs leases are deemed to be impaired, exploration expense is charged.

Unproved property costs consist mainly of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and to Block P in Equatorial Guinea.

In connection with the TransGlobe Acquisition as discussed under Part IV, Item 15., Note 4.

Acquisitions to the Consolidated Financial Statements, reserves in Egypt and Canada were also attributed to undeveloped properties and leasehold costs.

Unproved property costs consist mainly of acquisition costs related to undeveloped acreage in the Etame Marin, Niosi Marin, and Guduma Marin blocks in Gabon, the CI-705 block in Cote d’Ivoire and to Block P in Equatorial Guinea.

Business Combinations

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The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil, natural gas and NGLs properties.

If sufficient market data is not available regarding the fair values of proved and unproved

properties, estimates of the fair value of crude oil and gas reserves are prepared.

Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and capital costs are used to estimate future net cash flows.

If sufficient market data is not available regarding the fair values of proved and unproved properties, estimates of the fair value of crude oil and gas reserves are prepared.

Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and capital costs are used to estimate future net

For estimated proved reserves, the future net cash flows are discounted using a market-based discount rate and risk adjustment factors determined appropriate at the time of the acquisition.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity