VAALCO ENERGY INC /DE/ (EGY)

CIK: 0000894627. SIC: 1311 Crude Petroleum & Natural Gas. Latest 10-K as of: 2026-03-16.

SIC breadcrumb: Mining > SIC Major Group 13 > SIC 1311 Crude Petroleum & Natural Gas

SEC company page: https://www.sec.gov/edgar/browse/?CIK=894627. Latest filing source: 0000894627-26-000013.

Selected Fundamentals

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-03-16. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000894627.json. Derived margins, ratios, and free cash flow are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Free cash flow = operating cash flow - capital expenditures. Missing metrics are omitted rather than fabricated.

Ratios

ROE and ROA use period-end equity/assets. Liabilities / equity uses total liabilities divided by stockholders' equity. Current ratio uses current assets divided by current liabilities when both are reported.

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-11. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0000894627.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

Quarterly Charts

Macro Cross-References

• CPIAUCSL - Consumer Price Index for All Urban Consumers: All Items in U.S. City Average
• UNRATE - Unemployment Rate
• FEDFUNDS - Federal Funds Effective Rate
• CES0500000003 - Average Hourly Earnings of All Employees, Total Private
• DFEDTARU - Federal Funds Target Range - Upper Limit
• DFEDTARL - Federal Funds Target Range - Lower Limit
• DGS3MO - Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity
• DGS2 - Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity
• DGS10 - Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity
• DGS30 - Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity
• T10Y2Y - 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity
• CPILFESL - Consumer Price Index for All Urban Consumers: All Items Less Food and Energy
• CPIUFDSL - Consumer Price Index for All Urban Consumers: Food
• CPIENGSL - Consumer Price Index for All Urban Consumers: Energy
• CUSR0000SAH1 - Consumer Price Index for All Urban Consumers: Shelter
• PCEPI - Personal Consumption Expenditures: Chain-type Price Index
• PCEPILFE - Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index
• PPIACO - Producer Price Index by Commodity: All Commodities
• T10YIE - 10-Year Breakeven Inflation Rate
• U6RATE - Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons
• PAYEMS - All Employees, Total Nonfarm
• CIVPART - Labor Force Participation Rate
• EMRATIO - Employment-Population Ratio
• UNEMPLOY - Unemployed
• CE16OV - Employment Level
• ICSA - Initial Claims
• JTSJOL - Job Openings: Total Nonfarm
• JTSQUR - Quits: Total Nonfarm
• GDPC1 - Real Gross Domestic Product
• A191RL1Q225SBEA - Real Gross Domestic Product: Percent Change from Preceding Period
• INDPRO - Industrial Production: Total Index
• TCU - Capacity Utilization: Total Index
• HOUST - New Privately-Owned Housing Units Started: Total Units
• PERMIT - New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units
• RSAFS - Advance Retail Sales: Retail Trade
• PCE - Personal Consumption Expenditures
• DSPIC96 - Real Disposable Personal Income
• PSAVERT - Personal Saving Rate
• M2SL - M2
• BOPGSTB - U.S. International Trade in Goods and Services: Balance
• MSPUS - Median Sales Price of Houses Sold for the United States
• HSN1F - New One Family Houses Sold: United States
• RHORUSQ156N - Homeownership Rate in the United States
• TTLCONS - Total Construction Spending: Total Construction in the United States
• RRVRUSQ156N - Rental Vacancy Rate in the United States
• TOTALSL - Total Consumer Credit Owned and Securitized
• REVOLSL - Revolving Consumer Credit Owned and Securitized
• DRCCLACBS - Delinquency Rate on Credit Card Loans, All Commercial Banks
• GDP - Gross Domestic Product
• GPDI - Gross Private Domestic Investment
• GCE - Government Consumption Expenditures and Gross Investment
• PCEC - Personal Consumption Expenditures
• NETEXP - Net Exports of Goods and Services
• GFDEBTN - Federal Debt: Total Public Debt
• GFDEGDQ188S - Federal Debt: Total Public Debt as Percent of Gross Domestic Product
• FYFSD - Federal Surplus or Deficit
• FGRECPT - Federal Government Current Receipts
• FGEXPND - Federal Government: Current Expenditures
• MANEMP - All Employees, Manufacturing
• USCONS - All Employees, Construction
• USTRADE - All Employees, Retail Trade
• USFIRE - All Employees, Financial Activities
• USGOVT - All Employees, Government
• AWHAETP - Average Weekly Hours of All Employees, Total Private
• DGORDER - Manufacturers' New Orders: Durable Goods
• NEWORDER - Manufacturers' New Orders: Nondefense Capital Goods Excluding Aircraft
• BUSINV - Total Business Inventories
• EXPGS - Exports of Goods and Services
• IMPGS - Imports of Goods and Services
• IR - Import Price Index (End Use): All Commodities
• PPIFIS - Producer Price Index by Commodity: Final Demand

Latest quarter (10-Q)

Latest 10-Q source: 0000894627-26-000027.

Extracted structurally from real Item 2 body heading to real Item 3/4 boundary. Confidence: high. Filing date: 2026-05-11. Report date: 2026-03-31.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and may also include forward-looking information within the meaning defined under applicable Canadian securities laws (collectively, “forward-looking statements”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly Report that address activities, events or developments that we expect or anticipate may occur in the future, including, without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

•the impact of world health events, including any related impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity, when and if needed, disruptions in global supply chains and disruptions to our workforce;

•the impact of any future production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries (“OPEC”), as a result of agreements among OPEC, Russia and other allied producing countries with respect to crude oil production levels;

•the impact of the wide-ranging policy changes and numerous executive actions issued by the current U.S. presidential administration on topics including international trade, imposition of trade tariffs, energy resources, corporate taxes, global climate change initiatives, employment practices, corporate compliance programs, environmental regulations, as well as other matters;

•the macroeconomic, regulatory or other potential effects of a prolonged U.S. government shutdown;

•volatility of, and declines and weaknesses in crude oil, natural gas and natural gas liquids (“NGLs”) prices, as well as our ability to offset volatility in prices through the use of hedging transactions;

•the discovery, acquisition, development and replacement of crude oil, natural gas and NGLs reserves;

•impairments in the value of our crude oil, natural gas and NGLs assets;

•future capital requirements;

•our ability to maintain sufficient liquidity in order to fully implement our business plan;

•our ability to generate cash flows that, along with our cash on hand and our 2025 RBL facility, will be sufficient to support our operations and cash requirements;

•the ability of the BWE Consortium to successfully execute its business plan;

•our ability to attract capital or obtain debt financing arrangements;

•our ability to pay the expenditures required in order to develop certain of our properties;

•operating hazards inherent in the exploration for and production of crude oil, natural gas and NGLs;

•difficulties encountered during the exploration for and production of crude oil, natural gas and NGLs;

•the impact of competition;

•our ability to identify and complete complementary opportunistic acquisitions;

•our ability to effectively integrate assets and properties that we acquire into our operations;

•weather conditions;

•the uncertainty of estimates of crude oil and natural gas;

•currency exchange rates and regulations;

•unanticipated issues and liabilities arising from non-compliance with environmental regulations;

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•the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon;

•our limited control over the assets we do not operate;

•the ability of the FPSO in Cote d’Ivoire to return to service within the expected timeframe;

•the availability and cost of seismic, drilling and other equipment;

•difficulties encountered in measuring, transporting and delivering crude oil, natural gas and NGLs to commercial markets;

•timing and amount of future production of crude oil, natural gas and NGLs;

•hedging decisions, including whether or not to enter into derivative financial instruments;

•general economic conditions, including any future economic downturn, the impact of inflation or tariffs, disruptions in financial credit and other disruptions resulting from geo-political events such as the Russian invasion of Ukraine, conflicts in the Middle East, including the United States-Israel-Iran war, trade tensions between the U.S. and China and U.S. military operations in Venezuela;

•our ability to enter into new customer contracts;

•changes in customer demand and producers’ supply;

•actions by governments and other significant actors with respect to events occurring in the countries in which we operate;

•actions by our joint venture partners;

•compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;

•the outcome of any governmental audit;

•the anticipated impact on our business and operations of the OBBBA; and

•actions of operators of our crude oil, natural gas and NGLs properties.

The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2025 (“2025 Form 10-K”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report, and the 2025 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.

Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this “Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report.

INTRODUCTION

Vaalco is a Houston, Texas-based, African-focused independent energy company with strong production and reserve portfolio of assets in Gabon, Egypt, Côte d'Ivoire, Equatorial Guinea, Nigeria, as well as, prior to the Canada Assets Divestment, producing properties in Canada. We are currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

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Business Environment and Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment and uncertainties. These factors, and any changes to these factors, among others, could have a material adverse impact on our future revenues and overall profitability. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Form 10-K for further discussion of Trends and Uncertainties.

Commodity Prices – Uncertainties in the global supply chain and financial markets impact oil supply and demand and contribute to commodity price volatility. These uncertainties include the impacts of ongoing international conflicts, inflation, current and potential tariffs or other trade barriers, global trade policies, and actions taken by foreign oil and gas producing nations, including OPEC+. Changes in oil prices could result in adjustments to capital investment levels and allocation, which impact our production volumes.

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. Global markets are also experiencing volatility and uncertainty connected to the Russia-Ukraine war United States-Israel-Hamas conflict, United States-Israel-Iran war and the U.S intervention in Venezuela. 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. The duration and impact of these ongoing armed conflicts, and the potential of these conflicts spreading to more regions are uncertain and could adversely affect the global economy, financial markets, our customers and in turn us.

U.S. 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. 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 t

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high. Filing date: 2026-03-16. Report date: 2025-12-31.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management’s discussion and analysis describes the principal factors affecting our capital resources, liquidity, and results of operations. This management’s discussion and analysis should be read in conjunction with the accompanying Financial Statements and related notes, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this Annual Report. For discussion related to changes in financial condition and results of operations for 2024 as compared with 2023, refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2024 Form 10-K, which was filed with the SEC on March 17, 2025. Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” for further details about these statements.

INTRODUCTION

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 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. Business – Segment and Geographical Information.”

We intend to accelerate shareholder returns and increase shareholder value by controlling operating costs and capital expenditures, maximizing reserve recoveries and making disciplined strategic accretive acquisitions that meet our strategic and financial objectives.

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.

Recent Developments and Outlook

2025 Acquisition

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 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 below under

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

Commodity Prices

Prices for crude oil and condensate, NGLs and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the worldwide political and economic environment and the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors. Significant changes in oil and natural gas prices have a material impact on our liquidity. Declining commodity prices negatively affect our operating cash flow but have a positive indirect effect on operating expenses. The inverse is also true during periods of rising commodity prices. 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, 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.

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.

U.S. 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

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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

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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.

U.S. 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.

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RESULTS OF OPERATIONS

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

We reported a net loss for the year ended December 31, 2025 of $41.4 million 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.

Year Ended December 31,

Increase/

2025

2024

(Decrease)

(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)

Operating costs and expenses:

Production expense

158,177 

163,500 

(5,323)

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 

Credit (recovery) losses and other

106 

6,304 

(6,198)

Total operating costs and expenses

377,488 

342,570 

34,918 

Other operating income (expense), net

(2,391)

78 

(2,469)

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.

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.

Gabon

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 $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.

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Egypt

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 $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.

Canada

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. 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 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 expenses for the year ended December 31, 2025 of $8.9 million 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

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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 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. Summary of Significant Accounting Policies to the Consolidated Financial Statements. 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) for 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 lower in 2025 than the income tax expense in 2024 period as a result of lower revenues. See Part IV, Item 15., Note 7. Income Taxes to the Consolidated Financial Statements for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

Capital Expenditures

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 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.

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Recent Operational Updates

Gabon

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.

Egypt

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

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.

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. 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.

Canada

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.

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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

The price we receive for our crude oil significantly influences our revenue, profitability, liquidity, access to capital and prospects for future growth. Crude oil commodities and, therefore their prices can be subject to wide fluctuations in response to relatively minor changes in supply and demand. We believe these prices will likely continue to be volatile in the future.

Due to the inherent volatility in crude oil prices, we use commodity derivative instruments such as swaps to hedge price risk associated with a portion of our anticipated crude oil production. These instruments allow us to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. The instruments provide only partial protection against declines in crude oil prices and may limit our potential gains from future increases in prices. None of these instruments are used for trading purposes. We do not speculate on commodity prices but rather attempt to hedge physical production by individual hydrocarbon product in order to protect returns. The counterparty to our derivative swap transactions was a major oil company’s trading subsidiary, and our costless collars are with Glencore. We have not designated any of our derivative contracts as fair value or cash flow hedges. The changes in fair value of the contracts are included in the consolidated statements of operations and other comprehensive income (loss). We record such derivative instruments as assets or liabilities in the consolidated balance sheet. We do not anticipate any substantial changes in our hedging policy.

Please see Part IV, Item 15., Note 9. Derivatives in our Consolidated Financial Statements for more information on the related hedges.

Cash on Hand

At December 31, 2025 and 2024, we had unrestricted cash of $58.9 million and $82.6 million, respectively, which as of certain dates, exceeded Federal Deposit Insurance Corporation insurance limits. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

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. 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 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

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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

For information on the Merged Concession Agreement, see Part IV, Item 15., Note 11. Commitments and Contingencies to the Consolidated Financial Statements.

2025 RBL Facility Agreement and Available Credit

For information on our 2025 Facility Agreement and available credit, see Part IV, Item 15., Note 12. 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 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. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. 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 through the end of 2025. At December 31, 2025, the balance of the abandonment fund was $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. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. The Company is working with the Directorate of Hydrocarbons in Gabon to establish a payment schedule to resume funding of the abandonment fund. 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, 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. The annual costs of these leases are significant to us. For further information see Part IV, Item 15., Note 13. Leases to our Consolidated Financial Statements.

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.

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.

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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.

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.

Cash Flows

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

Year Ended December 31,

2025

2024

Increase (Decrease) in 2025 over 2024

(in thousands)

Net cash provided by operating activities before changes in operating assets and liabilities

$

117,263 

$

184,312 

$

(67,049)

Net change in operating assets and liabilities

95,404 

(70,594)

165,998 

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 

Effects of exchange rate changes on cash

83 

(3)

86 

Net change in cash, cash equivalents and restricted cash

$

(30,763)

$

(31,452)

$

689 

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 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, 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.

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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

We are subject to periodic routine audits by various government agencies, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Part IV, Item 15., Note 11. Commitment and Contingencies to the Consolidated Financial Statements for further discussion.

CRITICAL ACCOUNTING ESTIMATES

The preparation of Financial Statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used. Further, in some cases, GAAP allows more than one alternative accounting method for reporting. In those cases, our reported results of operations would be different should we employ an alternative accounting method. See Part IV, Item 15., Note 2. Summary of Significant Accounting Policies to the Consolidated Financial Statements for our accounting policy elections.

Asset Retirement Obligations

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. Estimating the future plugging and abandonment costs requires management to make estimates and judgments inherent in the present value calculation of the future obligation. These include ultimate plugging and abandonment costs, inflation factors, credit adjusted discount rates, and timing of settlement and changes in the legal, regulatory, environmental and political environments.

We account for asset retirement obligations as required by ASC 410 — Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. 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 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.

Income Taxes

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. 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

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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.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. When it is estimated to be more-likely-than-not that all or some portion of the deferred tax assets will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. 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, 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. A valuation allowance of $203.6 million has been established against the deferred tax assets as of December 31, 2025, as management has concluded that it was more-likely-than-not that only some portion of the deferred tax assets would be realized. In future periods, we may determine that it is more-likely-than-not that all or some portion of the deferred tax assets will be realized, and in such period all or a portion of this valuation allowance may be reversed as the evidence warrants.

In certain jurisdictions, we may deem the likelihood of realizing deferred tax assets as remote where we expect that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated financial position and results of operations. For further discussion, see Part IV, Item 15., Note 7. Income Taxes to the Consolidated Financial Statements.

Oil and Gas Accounting Reserves Determination

The successful efforts method of accounting depends on the estimated reserves we believe are recoverable from our crude oil, natural gas and NGLs reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data.

To estimate the economically recoverable crude oil, natural gas and NGLs reserves and related future net cash flows, we incorporate many factors and assumptions including:

•expected reservoir characteristics based on geological, geophysical and engineering assessments;

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

•future crude oil, natural gas and NGLs differentials;

•assumed effects of regulation by governmental agencies; and

•future development and operating costs.

We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially going forward as additional data from development activities and production performance becomes available and as economic conditions impacting crude oil, natural gas and NGLs prices and costs change.

Management is responsible for estimating the quantities of proved crude oil, natural gas and NGLs reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the U.S. as prescribed by the Society of Petroleum Engineers. 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. 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.

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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. The Technical & Reserves Committee and senior management meet with the reserve engineers periodically to review the reserves process and results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between us and the independent reserve engineers.

Reserves estimates are critical to many of our accounting estimates, including:

•determining whether or not an exploratory well has found economically producible reserves;

•calculating our unit-of-production depletion rates. Proved developed reserves estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense; and

•assessing, when necessary, our crude oil, natural gas and NGLs assets for impairment using undiscounted future cash flows based on management’s estimates. If impairment is indicated, discounted values will be used to determine the fair value of the assets. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.

See “Item 15. Exhibits and Financial Statement Schedules – Supplemental Information on crude oil, natural gas and NGLs Producing Activities (unaudited).”

Impairment of crude oil, natural gas and NGLs producing properties

We review the crude oil, natural gas and NGLs producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. 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 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.

Impairment of Unproved Property

We evaluate our undeveloped crude oil, natural gas and NGLs leases for impairment on at least a quarterly basis by considering numerous factors that could include nearby drilling results, seismic interpretations, market values of similar assets, existing contracts and future plans for exploration or development. 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, 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

We apply the acquisition method of accounting for business combinations, under which we record the acquired assets and assumed liabilities at fair value and recognize goodwill to the extent the consideration transferred exceeds the fair value of the net assets acquired. To the extent the fair value of the net assets acquired exceeds the consideration transferred, we recognize a bargain purchase gain.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. 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

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cash flows. 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. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

We estimate the fair values of the acquired assets and assumed liabilities as of the date of the acquisition, and our estimates are subject to adjustment through completion, which is in each case within one year of the acquisition date, based on our ongoing assessments of the fair values of property and equipment, intangible assets, other assets and liabilities and our evaluation of tax positions and contingencies.

ACCOUNTING STANDARDS

See Part IV, Item 15., Note 3. New Accounting Standards to the Consolidated Financial Statements.