Vaalco Energy Inc: Form 10-Q for the period ended Mar 31, 2026

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;
• 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.

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

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 and through the date of this filing, are not material and the Company is still assessing the impact of provisions that are not yet effective.

As a company, we remain focused on our overall business strategy to maximize the value of our current resources and expand into new development opportunities across our strategically complementary asset base. 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

Canada Assets Divestment

On February 4, 2026, the Company entered into an asset purchase agreement to sell all of our operating assets in Canada (the “Canada Assets Divestment”) to a third party purchaser for a purchase price of $24.4 million (C$33.4 million) to be settled in cash, subject to customary post-closing adjustments. The Canada Assets Divestment closed on February 19, 2026 with an effective date of February 1, 2026 for an adjusted purchase price of $25.5 million (C$34.9 million), subject to customary post-closing adjustments. The net cash proceeds from the divestment were primarily used to fund our capital expenditures and for working capital purposes. The Canada Assets Divestment represents the Company’s complete exit of its Canadian oil and gas operations.

Assumption of Operatorship

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.

Quarterly Cash Dividends

The Company paid a quarterly cash dividend of $0.0625 per share of common stock for the first quarter of 2026 ($0.25 annualized) on March 27, 2026 to stockholders of record at the close of business on February 27, 2026. The Company also announced its next quarterly cash dividend of $0.0625 per share of common stock for the second quarter of 2026 ($0.25 annualized) to be paid on June 26, 2026 to stockholders of record at close of business on May 22, 2026. 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.

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 ET-15H development well in the 1V block of Etame in December 2025. The well was completed and placed on production in February 2026 confirming expectations from the pilot well results. Although the West Etame exploration well (ET-14) encountered 10 meters of high quality sands, the target zone was water-bearing. The lower portion of the well was plugged and abandoned but the well bore was utilized and sidetracked in the upper portion of the well to drill the ET-14H development well in the Main Fault Block of Etame. The well was completed and placed on production in April 2026.

After completing our program at the Etame platform, we expect to move the drill rig to the Ebouri and SEENT platforms where we have several wells and workovers planned to enhance production and potentially add reserves.

The BWE Consortium completed its 3D seismic campaign across the Niosi and Guduma blocks in January 2026. The seismic data processing and interpretation are currently ongoing.

Egypt

The drilling campaign in Egypt began in December 2024 and continued throughout 2025 with the final well placed on production in January 2026. All wells drilled in the Eastern Desert successfully achieved their target.

During the first quarter of 2026, operations focused on interventions, workovers, and production optimization activities. A workover campaign to reactivate shut-in wells contributed to incremental production, while improved uptime supported increased average daily production rates.

Côte d'Ivoire

The Baobab FPSO completed its planned dry dock refurbishment in February 2026 and arrived back in Côte d'Ivoire in early April 2026. Reconnection activities are now underway and field production is 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 at the end of the third quarter of 2026. The drilling campaign is expected to bring meaningful additions to production from the main Baobab field in block 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.

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. The Company has 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.

Canada

As discussed above, in February 2026, the Company completely exited its Canadian oil and gas operations. Please see above under “Canada Assets Divestment,” for further discussion on the sale of the Canada operating assets.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the three months ended March 31, 2026 and 2025 are as follows:

(in thousands)

The $71.9 million decrease in net cash provided by operating activities during the three months ended March 31, 2026 compared to the three months ended March 31, 2025 was primarily due to lower crude oil, natural gas and natural gas liquids sales ($47.7 million) and an increase in net cash used in working capital and other assets and liabilities ($33.6 million).

Net cash used in investing activities during the three months ended March 31, 2026 was primarily attributable to $78.1 million for costs associated with the Baobab FPSO refurbishment work and the development drilling programs in Gabon, as well as maintenance, project costs and long lead items for Gabon and Côte d’Ivoire, offset by cash proceeds of $25.5 million from the Canada Assets Divestment. For the three months ended March 31, 2025, cash used in investing activities was due to capital spending 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.

Net cash provided by financing activities during the three months ended March 31, 2026 primarily consists of $92.0 million in proceeds from borrowings under the 2025 RBL Facility, offset by cash used of $6.7 million for dividend distributions, $1.2 million of payments for deferred financing costs and $3.2 million of principal payments on our finance leases. For the three months ended March 31, 2025, cash used in financing activities primarily included $6.6 million for dividend distributions, $5.1 million of payments for deferred financing costs and $2.9 million of principal payments on our finance leases.

Capital Expenditures

For the three months ended March 31, 2026, we had accrual basis capital expenditures of $73.5 million compared to $51.3 million accrual basis capital expenditures for the same period in 2025. For the three months ended March 31, 2026, our cash spending primarily related to the new wells drilled as part of the Phase Three drilling campaign in Gabon as well as expenditures associated with the refurbishment and reconnection activities of the FPSO in Côte d’Ivoire. During the same period in 2025, our cash spending primarily related to the new wells drilled as part of the drilling campaign in Egypt as well as expenditures associated with the preparation of the FPSO refurbishment in Côte d’Ivoire.

See discussion below in “Capital Resources, Liquidity and Cash Requirements” for further information.

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 and natural gas 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, costless collars and put options to hedge price risk associated with a portion of our anticipated crude oil and gas 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 and gas 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. We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility. 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 unaudited condensed consolidated statements of operations and other comprehensive income. We record such derivative instruments as assets or liabilities in the unaudited condensed consolidated balance sheets. Our 2025 RBL Facility requires us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production. See Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements for further discussion.

Capital Resources, Liquidity and Cash Requirements

Our primary sources of liquidity have been cash flows from operations, cash on hand and available borrowing capacity under the 2025 RBL Facility, and our primary use of cash has been to fund capital expenditures for development activities. At March 31, 2026, we had unrestricted cash of $48.0 million. 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 and reconnection, drilling programs, dividend payments, Merged Concession Agreement, 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.

Merged Concession Agreement

For information on the Merged Concession Agreement, see Part I, Item 1, Note 9. Commitments and Contingencies to the unaudited condensed consolidated financial statements.

2025 Facility Agreement and Available Credit

For information on our 2025 Facility Agreement and available credit, see Part I, Item 1, Note 10. Debt, to the unaudited condensed consolidated financial statements.

Cash Requirements

Our material cash requirements generally consist of the FPSO refurbishment and reconnection, finance and operating leases, capital projects, dividend payments, Merged Concession Agreement 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 extension of the Etame PSC, 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. At March 31, 2026, 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 unaudited condensed consolidated balance sheets. 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 2025, the Company commenced its Phase Three drilling campaign in Gabon. The BWE Consortium completed its 3D seismic campaign across the Niosi and Guduma blocks in January 2026. A rig has also been secured for the planned development drilling program in Côte d’Ivoire which is expected to begin during the third quarter of 2026.

Leases - We are a party to several operating and financing lease arrangements, including operating leases for the corporate office, a drilling rig, rental of marine vessels and a helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, generators and turbines used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations in Canada and Egypt. The annual costs of these leases are significant to us.

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”) for a total of $150 million over the 15-year license contract term. 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, all modernization payments had been fully settled either through actual cash payments or through the issuance of credit against receivables owed from EGPC. Through March 31, 2026, our financial work commitments have exceeded the five-year minimum $50 million threshold and any excess carries forward to offset against subsequent five-year commitments.

FPSO Refurbishment and Reconnection – The Baobab FPSO completed its planned dry dock refurbishment in February 2026 and arrived back in Côte d’Ivoire in early April 2026. Reconnection activities are now underway and field production is expected to restart during the second quarter of 2026.

Drilling Rig Commitment - The Company entered into the Bareboat Charter 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 purposes of maintaining and operating the drilling rig on its behalf. The Bareboat Charter and the service agreement commenced in November 2025 and has a noncancelable period of 300 days plus five single well options. The Bareboat Charter and the service agreement stipulate fixed day rates and other variable payments.

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. 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.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

There have been no material changes to our critical accounting policies and estimates subsequent to December 31, 2025. For a discussion of the Company's critical accounting policies for the fiscal year ended December 31, 2025, please see our 2025 Form 10-K.

NEW ACCOUNTING STANDARDS

See Part I, Item 1, Note 2. New Accounting Standards to the unaudited condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended March 31, 2026 Compared to the Three Months Ended March 31, 2025

Net loss for the three months ended March 31, 2026 was $93.8 million compared to a net income of $7.7 million during the same period of 2025. See discussion below for changes in revenues and expenses.

Crude oil, natural gas and NGLs revenues decreased $47.7 million, or approximately 43%, to $62.6 million during the three months ended March 31, 2026 from $110.3 million during the same period in 2025. The revenue decrease is primarily due to lower revenues in Gabon, Côte d’Ivoire and Canada.

(in thousands)

28

* Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil, natural gas and NGL revenues:

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 $21.4 million of revenue to the Company’s total revenue during the three months ended March 31, 2026, a decrease of $30.8 million from the $52.2 million of revenue reported during the three months ended March 31, 2025. The decrease in revenues is primarily due to the lower average realized sales price received in Gabon of $66.32 per Bbl for the three months ended March 31, 2026 compared to $79.25 per Bbl average realized sales price received during the same period in 2025. Additionally, sales volumes in Gabon decreased to 323 MBbls for the three months ended March 31, 2026 from the 658 MBbls reported during the same period of 2025. Gabon's share of crude oil inventory, excluding royalty barrels, was approximately 333 MBbls and 276 MBbls at March 31, 2026 and 2025, respectively.

Egypt

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, through EGPC. During the three months ended March 31, 2026, the oil sold in Egypt was through direct sales to EGPC. The Company’s Egypt segment contributed $38.9 million of revenue to the Company’s total revenue for the three months ended March 31, 2026, which is $5.0 million higher than the $33.9 million of revenue reported during the three months ended March 31, 2025. The increase in revenues was primarily due to the increase in average realized sales price from $52.85 per Bbl during the three months ended March 31, 2025 to $56.57 per Bbl during the same period in 2026. Sales volumes in Egypt slightly increased to 688 MBbls during the three months ended March 31, 2026 from 642 MBbls sold during the same period in 2025.

Côte 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 refurbishment which was completed in February 2026. The FPSO arrived back in Côte d’Ivoire in early April 2026. Reconnection activities are now underway and field production is 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 at the end of the third quarter of 2026. The drilling campaign is expected to bring meaningful additions to production from the main Baobab field in CI-40. As such, there were no revenues from the Côte d’Ivoire segment for the three months ended March 31, 2026. The Côte d’Ivoire segment reported revenues of $18.0 million during the three months ended March 31, 2025 with total sales volumes of 238 MBbls and an average realized sales price received of $75.87 per Bbl.

Canada

Prior to the Canada Assets Divestment, crude oil sales in Canada were normally sold through pipelines to a third party. The Company’s Canadian segment contributed $2.3 million of revenue to the Company’s total revenue for the three months ended March 31, 2026, or a decrease of $3.9 million, compared to $6.2 million of revenue reported during the three months ended March 31, 2025. The decrease in revenues was primarily due to the Canada Assets Divestment. We received a lower average realized sales price of $27.34 per Boe during the three months ended March 31, 2026 compared to $34.61 per Boe received during the same period in 2025. Sales volumes in Canada also decreased during the three months ended March 31, 2026 to 83 MBoe in comparison to 179 MBoe in the same period in 2025.

Production expenses decreased $16.4 million for the three months ended March 31, 2026 to $28.4 million from $44.8 million for the same period in the prior year. The decrease in production expenses was primarily driven by lower expenses in Gabon mainly due to the change in oil inventory adjustments. Production expenses associated with unsold crude oil inventory are capitalized and included in inventory, which are then subsequently expensed when oil inventory is sold. In addition, we had higher costs during the three months ended March 31, 2025 related to government audit settlements. We also had significantly lower production expense in Cote d’Ivoire as there were no production operations during the current period. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the three months ended March 31, 2026 slightly decreased to $25.89 per barrel from $26.05 per barrel for the three months ended March 31, 2025.

Exploration expense for the three months ended March 31, 2026 of $22.4 million was comprised of the cost of additional seismic data to be used in Niosi and Guduma blocks, and the costs of a well in Gabon that was determined to be unsuccessful. There were no exploration costs incurred during the same period in 2025.

Depreciation, depletion and amortization costs decreased $12.1 million, or approximately 40%, for the three months ended March 31, 2026 to $18.2 million from $30.3 million during the same period in 2025. The decrease in depreciation, depletion and amortization expense is due primarily to lower depletable costs in Gabon and to no production in Cote d’Ivoire during the current quarter.

Loss on asset divestment for the three months ended March 31, 2026 of $1.2 million was due to the Canada Assets Divestment which was completed in February 2026.

General and administrative expenses slightly decreased by $0.8 million, or 9%, for the three months ended March 31, 2026 to $8.3 million from $9.1 million during the same period in 2025. The decrease in general and administrative expenses is primarily due to a decrease in compensation expenses.

Credit losses and other increased by approximately $0.3 million during the three months ended March 31, 2026 compared to the same period in 2025. The increase in credit losses and other for the three months ended March 31, 2026, is primarily attributable to allowance charges related to receivables from joint venture partners.

Derivative instruments loss, net is attributable to our swaps and collars as discussed in Part I, Item 1, Note 7. Derivatives to the unaudited condensed consolidated financial statements. We recorded a $70.6 million net loss on derivative instruments for the three months ended March 31, 2026, which included an unrealized loss of $55.9 million related to the change in fair value of our commodity derivative contracts primarily driven by an increase in the futures curve for forecasted commodity prices and a realized loss of $14.6 million on matured commodity derivative contracts. We recognized a net loss on derivative instruments of $0.1 million during the same period in 2025. The increase in derivative losses was primarily due to a higher volume of outstanding derivative contracts entered into for the three months ended March 31, 2026 compared to the same period in 2025. Our derivative instruments currently cover a portion of our crude oil production through June 2027.

Interest expense, net was $1.7 million for the three months ended March 31, 2026 compared to an expense of $1.3 million during the same period in 2025. The increase in net interest expense for the three months ended March 31, 2026 primarily resulted from an increase in our amortization of debt issue costs, commitment fees incurred and interest incurred on our borrowings under the 2025 RBL Facility, partially offset by interest income.

Other income (expense), net was an expense of $1.0 million for the three months ended March 31, 2026 and 2025. Other income (expense), net, normally consists of foreign currency gains and losses.

Income tax expense for the three months ended March 31, 2026 was an expense of $4.3 million which includes a $2.9 million unfavorable 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 $1.4 million for the period. Income tax expense for the three months ended March 31, 2025 was $16.1 million, which includes a $0.7 million unfavorable 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, current income taxes were $15.4 million for the period.

MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.

FOREIGN EXCHANGE RISK

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency Central African, the CFA Franc, (the “CFA”, or “XAF”), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of March 31, 2026, we had net monetary liabilities of $42.9 million (XAF $24.3 billion) denominated in XAF. At March 31, 2026, we estimate that a 10% weakening of the CFA relative to the U.S. dollar would have a $3.9 million reduction in the value of these net liabilities. For the three months ended March 31, 2026, we had expenditures of approximately $11.0 million net to Vaalco, denominated in XAF.

Related to our Canadian operations, our currency exchange risk relates primarily to certain cash and cash equivalents, accounts receivable, lease obligations and accounts payable and accrued liabilities denominated in Canadian dollars. At March 31, 2026, we estimate that a 10% decrease in the value of the Canadian dollar against the U.S. dollar would decrease the value of the net monetary assets for the three months ended March 31, 2026 by approximately $0.1 million. Conversely, a 10% increase in the value of the Canadian dollar against the U.S. dollar would increase the value of the net assets for the three months ended March 31, 2026 by approximately $0.1 million.

We are also exposed to foreign currency exchange risk on cash balances denominated in Egyptian pounds. Some collections of accounts receivable from the Egyptian Government are received in Egyptian pounds, and while we are generally able to use the Egyptian pounds received on accounts payable denominated in Egyptian pounds, there remains foreign currency exchange risk exposure on Egyptian pound cash balances. At March 31, 2026, we estimate that a 10% increase in the value of the Egyptian pound against the U.S. dollar would increase the U.S dollar value of net liabilities for the three months ended March 31, 2026 by $3.6 million. Conversely, a 10% decrease in the value of the Egyptian pound against the U.S. dollar would decrease the U.S dollar value of net liabilities for the three months ended March 31, 2026 by $3.0 million.

In Côte d'Ivoire, our currency exchange risk also relates primarily to certain cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities denominated in Swedish Krona. We estimate that a 10% increase in the value of the Swedish Krona against the U.S. dollar would increase the value of the U.S. dollar value of net liabilities for the three months ended March 31, 2026 by approximately $1.1 million. Conversely, a 10% decrease in the value of the Swedish Krona against the U.S. dollar would decrease the U.S. dollar value of net liabilities for the three months ended March 31, 2026 by approximately $0.9 million.

We do not utilize derivative instruments to manage foreign exchange risk.

We maintain nominal balances of British Pounds Sterling to pay in-country costs incurred in operating our London office. Foreign exchange risk on these funds is not considered material.

COUNTERPARTY RISK

We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparties. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.

COMMODITY PRICE RISK

Our major market risk exposure continues to be the prices received for our crude oil, natural gas and NGLs production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil, natural gas and NGLs have been volatile and unpredictable in recent years, and this volatility may continue. Sustained low crude oil, natural gas and NGLs prices or a resumption of the decreases in crude oil, natural gas and NGLs prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms.

At March 31, 2026, the Company had open commodity derivative contracts covering our anticipated future production as follows:

Oil and gas properties are assessed for impairment annually as well as whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company would estimate the fair value of its properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved and probable reserves, estimated future commodity prices, future production estimates, and anticipated capital and operating expenditures, using a commensurate discount rate. Unfavorable changes in any of these assumptions could result in a reduction in undiscounted future cash flows and could indicate property impairment. Uncertainties related to the primary assumptions could affect the timing of an impairment. In most cases, the assumption that generates the most variability in undiscounted future net cash flows is future oil and gas prices. We observed volatility in commodity prices during the three months ended March 31, 2026, however, no triggering events were identified and therefore no impairment was recorded at March 31, 2026.

If crude oil sales were to remain constant at the most recent annual sales volumes, a $5 per Bbl decrease in crude oil price would decrease our revenues and operating income or increase our operating loss for the three months ended March 31, 2026 as follows:

With respect to our crude oil sales in Gabon, Egypt and Côte d'Ivoire, the prices received are based on Dated Brent prices plus or minus a differential. With respect to our crude oil and NGLs sales in Canada, prior to the Canadian Assets Divestment, the prices received are/were based on NYMEX WTI (West Texas Intermediate) prices plus or minus a differential. Natural gas sales are/were based on the Canadian index price whose price is based, in part, on the NYMEX Henry Hub Natural Gas futures contracts. Egypt production is based on Dated Brent prices, less a quality differential and is shared with the Egyptian government. When the price of oil increases, it takes fewer barrels to recover costs (cost oil or cost recovery barrels) which are assigned 100% to the Company.

Exploration and production activities of our assets in Gabon, Egypt, Cote d'Ivoire, and Equatorial Guinea are generally governed by PSCs. The PSCs provide for cost recovery per quarter up to a maximum percentage of total production. Timing differences often exist between Vaalco’s recognition of costs and their recovery as Vaalco accounts for costs on an accrual basis, whereas cost recovery is determined on a cash basis. If the eligible cost recovery is less than the maximum defined cost recovery, the difference is defined as “excess”. Production sharing splits are set in each contract for the life of the contract. Typically, the government’s share of Profit Oil increases when production exceeds pre-set production levels in the respective contracts. During times of high oil prices, the Company may receive less cost oil and may receive more profit-sharing oil. During times of lower oil prices, the Company receives more cost oil and may receive less Profit Oil.

INTEREST RATE RISK

As of March 31, 2026, our primary exposure to interest rate risk resulted from our $152.0 million of outstanding borrowings under our 2025 RBL Facility. The borrowing accrues interest at a rate of 10.2% per annum which is based on the Term SOFR plus the applicable margin of 6.5% per annum. We currently do not hedge our interest rate exposure. We estimate that a 10% increase in the applicable average interest rates during the time from the date the debt was drawn through March 31, 2026 would have resulted in an increase in interest expense of $0.2 million. Additionally, changes in market interest rates could impact interest costs associated with any future indebtedness.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer (“CEO”) and principal financial officer (“CFO”), to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures. Our management, including our CEO and CFO, have evaluated the effectiveness of our disclosure controls and procedures pursuant to Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this report. Based on their evaluation as of March 31, 2026, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal control over financial reporting during the three months ended March 31, 2026 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2025 Form 10-K. There have been no material changes in our risk factors from those described in our 2025 Form 10-K.