EGY 10-K & 10-Q changes, risk factors and insider trading
Vaalco Energy Inc. · NYSE · Crude Petroleum & Natural Gas · CIK 894627 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “Provisions of our agreements could discourage an acquisition of us by a third-party.”
Removed heading “We may not generate sufficient cash to satisfy our payment obligations under the Merged Concession Agreement or be able to collect some or all of our receivables from EGPC, which could negatively affect our operating results and financial condition.”
Removed heading “There are no assurances that we will be able to extend the Block CI-40 PSC.”
Removed heading “We have identified material weaknesses in our internal control over financial reporting for the fiscal year ended December 31, 2024. If we are unable to remediate these material weaknesses or if we identify additional material weaknesses in the future or otherwise fail to maintain effective internal control over financial reporting, we may not be able to accurately or timely report financial information.”
Removed heading “We may be exposed to the risk of earthquakes in Alberta, Canada.”
Removed heading “There may be valid challenges to title or legislative changes which affect our title to the oil, natural gas and NGLs properties we control in Canada.”
Largest changes
“If we are unable to remediate our existing or any future material weaknesses in our internal control over financial reporting, our ability to record, process or report financial information accurately and to prepare financial statements in an accurate and timely manner could adversely be affected, which could subject us to litigation or investigations requiring management resources and payment of legal and other expenses, negatively affect investor confidence in our financial statements and adversely impact our stock price.”see in full comparison
“We have identified material weaknesses in our internal control over financial reporting for the fiscal year ended December 31, 2024. If we are unable to remediate these material weaknesses or if we identify additional material weaknesses in the future or otherwise fail to maintain effective internal control over financial reporting, we may not be able to accurately or timely report financial information.”see in full comparison
“In addition, any disruption in the operations of the U.S. federal government, including as a result of any future temporary or prolonged shutdowns resulting from the failure of Congress to enact appropriations bills, raise the federal debt ceiling or otherwise, could adversely affect our business, operations and financial condition. Recently, beginning on October 1, 2025 through November 12, 2025, the U.S. federal government shut down, during which time certain regulatory agencies, such as the SEC, furloughed large numbers of employees and stopped routine activities and operations. …”see in full comparison
Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce the emissions of GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG emissions reporting obligations and other regulatory programs that limit or require control of GHG emissions from certain sources. These programs may limit our ability to produce crude oil, natural gas and NGLs, limit our ability to explore in new areas, or may make it more expensive to produce. In addition, these programs may reduce demand for our product either by incentivizing or mandating the use of other alternative energy sources, by prohibiting the use of our product, by requiring equipment using our product to shift to alternative energy sources, or by directly increasing the cost of fossil fuels to consumers. Additionally, in March 2024, the SEC adopted final rules intended to enhance and standardize climate-related disclosures by public companies and in publicsee in full comparisonofferings;offerings.theseImmediately after the SEC’s release of the final rules, several lawsuits were filed to challenge their legality, and the rulesarewere stayed pending judicial review. On March 27, 2025, theoutcomeSEC ended its defense ofconsolidatedthe final rules on climate-related disclosures, effectively withdrawing its support for the regulation; however, the rules remain on hold pending such legalchallengeschallenges, which are currently held in abeyance by the Eighth Circuit Court ofAppeals.Appeals until such time as the SEC determines whether the rules will be rescinded, repealed, modified or defended in litigation.
“As disclosed in Part II, Item 9A, “Controls and Procedures,” we have identified material weaknesses in our internal control over financial reporting related to general information technology controls, effectiveness of control environment, risk assessment and design and process-level controls. A material weakness is a deficiency or a combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the registrant's financial statements will not be prevented or detected on a timely basis. …”see in full comparison
“Heightened expectations for companies to address ESG matters, including climate change, social license to operate, human rights, and governance, have a myriad of potential impacts on our business. Investors, lenders, and other stakeholders are increasingly factoring these issues into investment, financing, and business decisions, often relying on ESG ratings from third-party agencies. …”see in full comparison
Full comparison: every changed paragraph (59)
Our exploration and development activities, as well as our active pursuit of complementary opportunistic acquisitions, are capital intensive. To replace and grow our reserves, we must make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of crude oil, natural gas and NGLs reserves. Historically, we have financed these expenditures primarily with cash from operations, debt, asset sales and private sales of equity. We are the operator of the Etame Marin block offshore Gabon, and are responsible for contracting on behalf of all the remaining parties participating in the project and rely on our joint venture owners to pay for 36.4% of the offshore Gabon budget. With respect to Block P, as the EG MMH approved our appointment asappointed technical operator in August 2020 and, since we were appointed,operator, we rely on the timely payment of cash calls by our joint venture owners to pay for 46.3% of the Equatorial Guinea budget, except during any development phases where we have agreed or will agree to carry their interests. The continued economic health of our joint venture owners could be adversely affected by low crude oil prices, thereby adversely affecting their ability to make timely payment of cash calls.
Provisions of our agreements could discourage an acquisition of us by a third-party.
Certain provisions of our production sharing contracts, joint operating agreements and other agreements could make it more difficult or more expensive for a third-party to acquire us or our assets, or may even prevent a third-party from acquiring us or our assets. For example, some of these agreements contain restrictions on assignments of our assets, including requirements to obtain consent from applicable counterparties, preemption rights and requirements to make bonus payments. In some cases, these restrictions apply to “indirect assignments.” By discouraging an acquisition of us or our assets by a third-party, these provisions could have the effect of deterring otherwise interested third-parties from proposing or consummating these acquisitions. This could deprive the holders of our common stock of an opportunity to sell their common stock at a premium over prevailing market prices.
We may not generate sufficient cash to satisfy our payment obligations under the Merged Concession Agreement or be able to collect some or all of our receivables from EGPC, which could negatively affect our operating results and financial condition.
Under the Merged Concession Agreement, the Company is obligated to make modernization payments that total $65 million and are payable over six years from the Merged Concession Effective Date, of which $45.0 million plus a $1.0 million signing bonus have been paid as of December 31, 2024. Under the Merged Concession Agreement, the Company will be required to pay an additional $10 million on February 1st for each of the next two years. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024 payments and issue two $10.0 million credits against receivables owed from EGPC. In addition, the Company has also committed to spending a minimum of $50 million over each five-year period for the 15 years of the primary term (total $150 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which would be subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control. We may be unable to maintain a level of cash flow sufficient to permit us to satisfy the payment obligations under the Merged Concession Agreement. If we are unable to satisfy our obligations, it is possible that EGPC could seek to terminate the Merged Concession Agreement, which would negatively affect our operating results and financial condition.
In addition, as of the Merged Concession Effective Date, an effective date adjustment was owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date (as defined herein) (the “Effective Date Adjustment”). The Company recognized a receivable in connection with the Effective Date Adjustment of $67.5 million as of October 2022, based on historical realized prices (the “Backdated Receivable”). In 2023 and 2024, the Company received payments or provided offsets against the Backdated Receivable. As of December 31, 2024, the remaining net receivable of $33.2 million is recorded in the “Egypt receivables and other” line item on our Consolidated Balance Sheet. If EGPC’s financial position becomes impaired or if EGPC disputes or refuses to pay some or all of the said amount, our ability to fully collect such receivable from EGPC could be impaired, which could negatively affect our operating results and financial condition.
There are no assurances that we will be able to extend the Block CI-40 PSC.
The Block CI-40 PSC expires in April 2028. The Block CI-40 PSC can be extended by 10 years so long as certain conditions are met. Negotiations to extend the Block CI-40 PSC began in January 2024, led by the operator, CNR International (Côte d'Ivoire) S.A.R.L (the “Operator”), with the Director General of Hydrocarbons and the Government of the Côte d’Ivoire. Any extension is subject to approval of the Council of Ministers and formal approval by presidential decree. There can be no assurance that an extension will be approved or that any extension’s terms will not contain terms less favorable than our present arrangement. If the Block CI-40 PSC expires, our results of operations would be adversely affected.
As an offshore asset, we, along with the operator and contractors of the Block CI-40 PSC, depend on the FPSO to store the crude oil produced prior to sale to customers. TheAs FPSOpart contractof expiresthe in December 2025. The FPSO will be in transit toplanned dry dock inrefurbishment, earlythe 2025Baobab for planned maintenance and upgrades. ItFPSO ceased hydrocarbon production as scheduled on January 31, 20252025, andwith the final lifting of crude oil fromlifting the FPSO concluded onin February 6, 2025. The project team mobilization efforts are on schedule and have significantly progressed, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO. The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departuredeparted from the field aroundin late March 2025 and arrived at the shipyard in Dubai in May 2025. DuringAlthough, thisthe time,refurbishment productionwork relatingwas completed in February 2026 and the Baobab FPSO has commenced its mobilization back to theCote Block CI-40 PSC will be halted and we will receive no revenues from the Block CI-40 PSC. Additionally,d’Ivoire, there can be no assurance that the FPSO will return to service in the expected timeframe or that the costs of returning it to service will not be more than expected, and in either such case our results would be adversely affected. In addition, there can be no assurance that wells that are currently shut in will be returned to production on a timely basis, if at all, or at historical or anticipated production levels.
In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil, natural gas and NGLs we have entered into and may continue to enter into derivative arrangements with respect to a portion of our expected production in order to hedge against potential commodity price declines. In addition, under the 2025 RBL Facility agreement, if the aggregate borrowings under the 2025 RBL Facility exceeds 35% of the lower of (a) the available total commitments and (b) the applicable borrowing base amount, we are also required to enter into commodity price hedge positions covering certain volumes of anticipated future production set out in the banking case.
Our ability to collect payments from the sale of crude oil, natural gas and NGLs from our customers depends on the payment ability of our customer base, which may include a small number of significant customers. For example, our revenue concentration by customer for each of the Gabon, Egypt, and Cote d’Ivoire operating segments for the year ended December 31, 2025, was with a single respective significant customer. If our significant customers fail to pay for any reason, we could experience a material loss. In addition, if our significant customers cease to purchase or reduce the volume they purchase of our crude oil, natural gas or NGLs, the loss or reduction could have a detrimental effect on our production volumes and may cause a temporary interruption in sales of, or a lower price for, our crude oil, natural gas and NGLs.
In addition, we are and may in the future be exposed to third-party credit risk through our contractual arrangements with governmental entities in countries where we operate. Significant changes in the crude oil industry, including fluctuations in commodity prices and economic conditions, environmental regulations, government policy, royalty rates and other geopolitical factors, could adversely affect our ability to realize the full value of our accounts receivable from government entities in countries where we operate. Historically, we have had significant account receivables outstanding from governmental entities in countries where we operate. For example, while EGPC has made regular payments of these amounts owing,amounts, the timing of these payments hashave historically been longer than the normal industry standard. In addition, EGPC has at times faced difficulties in accessing foreign exchange markets for the purpose of obtaining U.S. dollars in exchange for Egyptian pounds. In the event the governments of the countries where we operate fail to meet their respective obligations or we are forced to accept payment in foreign currencies, such failures could materially adversely affect our financial and operational results.
We are also exposed to third-party credit risk through our banking relationships in the jurisdictions in which we operate. RecentIn 2023, macroeconomic conditions have caused turmoil in the banking sector in the United States and elsewhere. IfWe were not impacted by such turmoil. However, if similar conditions arise in the banking sector again and if any of the banks in which we keep our deposits is affected by such turmoil, we could be materially and adversely affected.
We face risks related to geopolitical events, international hostility, epidemics, outbreaks and other macroeconomic events that are outside of our control. The occurrence of certain geopolitical events, including those arising from terrorist activity, international hostility, public health crises, and the economic impact of global trade tensions and the imposition of tariffs, could significantly disrupt our business and operational plans and adversely affect our results of operations, cash flows, financial condition and liquidity. For instance, the ongoing conflicts in the Middle EastEast, including the United States-Israel-Iran war and between Russia and Ukraine have and may continue to cause geopolitical instability, and adversely impact the global economy, supply chains and specific markets and industries. Although we are not able to enumerate all potential risks to our business resulting from these and other similar events, we believe that such risks include, but are not limited to, the following:
•logistical challenges, including those resulting from border closures and travel restrictions, as well as the possibility that our ability to continue production may be interrupted, limited or curtailed if workers and/or materials are unable to reach our offshore platformsplatforms, our FPSO vessel and our FSO charter vessel or our counterparties are unable to lift crude oil from our FPSO vessel or our FSO charter vessel;
In early2025 2025,and continuing into 2026, the newcurrent U.S. presidential administration announcedhas implemented wide-ranging policy changes and issued numerous executive actions on topics including international trade, energy resources, corporate taxes, global climate change initiatives, employment practices, corporate compliance programs,programs and environmental regulations, as well asamong other matters. Further,In addition, the new presidential administration has indicated an intentcontinued to makepursue structural changes to the executive branch of the federal government, including significant reductions in the federal workforce.workforce Continuingand reorganization of certain regulatory agencies. Ongoing legal challenges to many of the policy changes and executive actions are expected. Such actions may directly or indirectly impact our industry and could lead to increased regulatory uncertainty and volatility. We cannot predict how these policy changes and executive actions willremain beunresolved, implementedcontributing andto interpreted,increased orregulatory the ultimate effect they will have on our business, financial condition and results of operations.uncertainty.
In addition, any disruption in the operations of the U.S. federal government, including as a result of any future temporary or prolonged shutdowns resulting from the failure of Congress to enact appropriations bills, raise the federal debt ceiling or otherwise, could adversely affect our business, operations and financial condition. Recently, beginning on October 1, 2025 through November 12, 2025, the U.S. federal government shut down, during which time certain regulatory agencies, such as the SEC, furloughed large numbers of employees and stopped routine activities and operations. Additionally, on October 10, 2025, the U.S. federal government implemented substantial layoffs and workforce reductions in connection with the federal government shutdown, which resulted in the suspension or delay of various government-funded programs. Furthermore, the recent federal government shutdown resulted in reduced availability of government services, and the suspension or delay of activities by key agencies that regulate or otherwise interact with our business, including the SEC. As a result, review and approval of our filings, applications, and submissions could be delayed, and we may be unable to access or rely upon certain government data or systems. Any U.S. federal government shutdown or prolonged budget negotiation uncertainty may further adversely affect the broader U.S. economy, investor confidence, and capital markets. Such conditions could negatively impact the liquidity or trading volume of our securities, which in turn could have a material adverse effect on our business, results of operations, and stock price.
Furthermore, geopolitical events, including the recent developments in Venezuela and Iran and changing U.S. foreign policy priorities, have heightened volatility in the regulatory environment affecting our industry. We cannot predict how these policy changes, executive actions, and geopolitical events will be implemented or interpreted or the impact of a possible U.S. federal government shutdown or prolonged budget negotiation, or the ultimate effect they will have on our business, financial condition, and results of operations.
Private ownership of crude oil reserves under crude oil leases in the U.S. differs distinctly from our rights in foreign reserves where the state generally retains ownership of the minerals and, in many cases participates in, the exploration and production of hydrocarbon reserves. In the foreign countries in which we may do business, the state generally retains ownership of the minerals and consequently retains control of, and in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the U.S. may be materially affected by host governments.
Private ownership of crude oil reserves under crude oil leases in the U.S. differs distinctly from our rights in foreign reserves where the state generally retains ownership of the minerals and, in many cases participates in, the exploration and production of hydrocarbon reserves. Accordingly, operations outside the U.S. may be materially affected by host governments. While the laws of each of Gabon, Cote d'Ivoire and Equatorial Guinea recognize private and public property and the right to own property is protected by law, the laws of each country reserve, at the respective government’s discretion, the right to expropriate property and terminate contracts (including the Etame PSC, the Block CI-40 PSC, and the Block P PSC) for reasons of public interest, subject to reasonable compensation, determinable by the respective government in our discretion. The terms of the Etame PSC include provisions for, among other things, payments to the government of Gabon for a 13% Royalty Interest based on crude oil production at published prices and payments for a shared portion of Profit Oil, based on daily production rates, which such Profit Oil has been and can continue to be taken in-kind through taking crude oil barrels rather than making cash payments. In Canada, majority of the mineral rights are usually held by a provincial government, also known as the Crown, but a small portion, called the freehold mineral rights, may be held by others such as individuals, families or businesses. In exchange for the right to develop oil and natural gas resources, companies make royalty payments to the Crown, which are calculated by taking a percentage of revenues generated from the sale of oil and natural gas.
We have operated in Gabon since 1995 and believe we have good relations with the current Gabonese government. However, there can be no assurance that present or future administrations or governmental regulations in Gabon will not materially adversely affect our operations or cash flows.
The respective applicable laws governing the exploration and production of hydrocarbons in Gabon, Cote d'Ivoire and Equatorial Guinea (Law No. 002/2019 in Gabon, Law No. 96-669 in Cote d'Ivoire, and Law No. 8/2006 in Equatorial Guinea) each provide their respective government officials with significantly broad regulatory, inspective and auditing powers with respect to the performance of petroleum operations, which include the powers to negotiate, sign, amend and perform all contracts entered into between the respective governments and independent contractors. The executive branches of each respective government also retain significant discretionary powers, giving considerable control over the executive, judiciary and legislative branches of each government, and the ability to adopt measures with a direct impact on private investments and projects, including the right to appoint ministers responsible for petroleum operations. Further, in Equatorial Guinea, any new PSC or equivalent agreement for the exploration and exploitation of hydrocarbons is subject to presidential ratification before it can become effective.
Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Gabon, Egypt, Cote d'Ivoire, Equatorial GuineaNigeria and Egypt.Equatorial Guinea.
For example, in September 2023, Gabon experienced a largely non-violent, military coup d’état and the country’s leadership changed hands. The group leading the coup created a Committee for the Transition and Restoration of Institutions and a new president was sworn in on the basis of a transition charter adopted by the group leading the coup. The new president has indicated that a new constitution for Gabon will be adopted and that elections will be held after a transition period. No assurance can be given that any such new constitution will be adopted or if adopted, that the content thereof will be in line with Gabon’s existing laws. Any of these developments may have an adverse effect on our operations and financial results.
The U.S. inflation rate steadilyhas rosefluctuated inthroughout 20212024 and into2025, 2022and beforeit eventuallyremains declining throughout 2023. During 2024, the U.S. inflation rate remained stable when comparedclose to the lasthistoric halflevels of 2023, yet remained slightly higher than historical averages. However,over the U.S.past several decades. Although the current outlook is uncertain, heightened inflation ratemay rose slightly in January 2025 and the U.S. inflation rate could rise significantly againpersist in the future.near to medium-term, particularly in the U.S., with the possibility that monetary policy may tighten in response. In addition, global and industry-wide supply chain disruptions have resulted in shortages in labor, materials and services. Such shortages have resulted in inflationary cost increases for labor, materials and services and could continue to cause costs to increase, or cause a scarcity of certain products and raw materials. To the extent inflation remains elevated, we may experience further cost increases for our operations, including oilfield services and equipment as a result of increasing prices of oil, natural gas and NGLs, increased drilling activity in our areas of operations, and increased labor costs. An increase in the prices of oil, natural gas and NGLs may cause the costs of materials and services we use to rise. We cannot predict any future trends in the rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through higher commodity prices and revenues, could negatively impact our business, financial condition and results of operation.
In addition, from time to time, emerging market countries such as those in which we operate adopt measures to restrict the availability of the local currency or the repatriation of capital across borders. These measures are imposed by governments or central banks, in some cases during times of economic instability, to prevent the removal of capital or the sudden devaluation of local currencies or to maintain in-country foreign currency reserves. In addition, many emerging markets countries require consents or reporting processes before local currency earnings can be converted into U.S. dollars or other currencies and/or such earnings can be repatriated or otherwise transferred outside of the operating jurisdiction. These measures may have a number of negative effects on us, including the reduction of the immediately available capital that we could otherwise deploy for investment opportunities or the payment of expenses. In addition, measures that restrict the availability of the local currency or impose a requirement to operate in the local currency may create other practical difficulties for us.
We currently do not utilize derivative instruments to manage these foreign currency risks. As a result, our consolidated earnings and cash flows may be impacted by movements in the exchange rates.
We are subject to the provisions of the U.S. Foreign Corrupt Practices Act, the UK Bribery Act, the Corruption of Foreign Public Officials Act (Canada) and other similar laws. The foregoing laws prohibit companies and their intermediaries from making improper payments to officials for the purpose of obtaining or retaining business. In addition, such laws require the maintenance of records relating to transactions and an adequate system of internal controls over accounting. There can be no assurance that our internal control policies and procedures, compliance mechanisms or monitoring programs will protect us from recklessness, fraudulent behavior, dishonesty or other inappropriate acts or adequately prevent or detect possible violations under applicable anti-bribery and anti-corruption legislation.
We have identified material weaknesses in our internal control over financial reporting for the fiscal year ended December 31, 2024. If we are unable to remediate these material weaknesses or if we identify additional material weaknesses in the future or otherwise fail to maintain effective internal control over financial reporting, we may not be able to accurately or timely report financial information.
As disclosed in Part II, Item 9A, “Controls and Procedures,” we have identified material weaknesses in our internal control over financial reporting related to general information technology controls, effectiveness of control environment, risk assessment and design and process-level controls. A material weakness is a deficiency or a combination of deficiencies in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the registrant's financial statements will not be prevented or detected on a timely basis. As a result of the material weaknesses, we concluded that our internal control over financial reporting and related disclosure controls and procedures were not effective as of December 31, 2024. We cannot be certain that the measures we may take in the future will be sufficient to remediate the control deficiencies that led to our material weaknesses in our internal control over financial reporting or that they will prevent or avoid potential future material weaknesses. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, an evaluation of controls can only provide reasonable assurance that all material control issues and instances of fraud, if any, have been or will be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistakes. Further, controls can be circumvented by the individual acts of some persons or by two or more persons acting in collusion. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of inherent limitations in any control system designed under a cost-effective approach, misstatements due to error or fraud may occur and not be detected. A failure of the controls and procedures to detect error or fraud could seriously harm our business and results of operations.
If we are unable to remediate our existing or any future material weaknesses in our internal control over financial reporting, our ability to record, process or report financial information accurately and to prepare financial statements in an accurate and timely manner could adversely be affected, which could subject us to litigation or investigations requiring management resources and payment of legal and other expenses, negatively affect investor confidence in our financial statements and adversely impact our stock price.
We may be exposed to the risk of earthquakes in Alberta, Canada.
The AER monitors seismic activity across the province of Alberta in Canada to assess the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further. The AER has developed monitoring and reporting requirements that apply to all oil and natural gas producers working in certain areas where the likelihood of an earthquake is higher, and implemented the requirements in Subsurface Order Nos. 2, 6, and 7 (the “Seismic Protocol Regions”). While we do not have operations in the Seismic Protocol Regions, we own production and working interest facilities and assets in the Harmattan area of west central Alberta and are exposed to the risks of earthquakes in that region. We routinely conduct hydraulic fracturing in our drilling and completion programs.
There may be valid challenges to title or legislative changes which affect our title to the oil, natural gas and NGLs properties we control in Canada.
Although title reviews may be conducted in Canada prior to the purchase of oil, natural gas and NGLs producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise. Due in part to the nature of property rights development historically in Canada as well as the common practice of splitting legal and beneficial title, public registries are not determinative of actual rights held by parties. Further, the fragmented nature of oil and gas rights, which may be held by the government or private individuals and companies, and may be split among a great number of different granting documents, means that despite best efforts of parties, latent defects may not be immediately discoverable. As such, our actual interest in properties may accordingly vary from our records. If a title defect does exist, it is possible that we may lose all or a portion of the properties to which the title defect relates, which may have a material adverse effect on our business, financial condition, results of operations and prospects. There may be valid challenges to title or legislative changes, which affect our title to the oil and natural gas properties that we control in Canada that could impair our activities and result in a reduction of the revenue we receive. Additionally, title claims by Indigenous groups could, among other things, delay or prevent the exploration or development of our properties, which in turn could have a material adverse effect on our business, financial condition, results of operations and prospects.
In December 2021 and during 2022, the Bank of Central African States (“BEAC”), which is the central bank for the Central African Economic and Monetary Community (“CEMAC”),CEMAC, passed new regulations and instructions for the CEMAC FX regulations, which were introduced in 2018, that only apply to the extractive industry. The intent of the new regulations is to ensure the application of the FX regulations as of January 1, 2022, without impeding the operations of the extractive industry. Due to the lack of necessary banking infrastructure and preparedness by the banking sector and the various government agencies to apply the new regulations, it is foreseeable that we will run the risk of seeing delays in paying our vendors and domiciliation of goods and services into the CEMAC region throughout 20242026 and beyond.
As of December 31, 2024,2025, we had $190.0 million of aggregate facility commitments, $130.0 million of available borrowing capacity and $60.0 million of outstanding borrowings under the amount2025 availableRBL to be drawn under our Facility Agreement was $31.3 million, none of which had been drawn.Facility. An increase in interest rates could result in a significant increase in the amount we pay to service any subsequently drawn, and any future other debt taken out by us, resulting in a reduced amount available to fund our exploration and development activities and, if applicable, the cash available for dividends. Such an increase could also negatively impact the market price of the shares of common stock.
If crude oil, natural gas or NGLs prices decline, we expect that the estimated quantities and present values of our reserves will be reduced, which may necessitate further write-downs. Any future write-downs or impairments could have a material adverse impact on our results of operations. A material decline in prices could also result in a reduction of our net production revenue. Any substantial and extended decline in the price of oil, natural gas and NGLs would have an adverse effect on the carrying value of our reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on our business, financial condition, results of operations and prospects. Volatile oil, natural gas and NGLs prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil, natural gas and NGLs producing properties, as buyers and sellers have difficulty agreeing on such values. Price volatility also makes it difficult to budget for, and project the return on, acquisitions and development and exploitation projects.
An increased societal and governmental focus on ESG andmatters, including climate change issuesissues, may adversely impact our business, impact ourhinder access to investors and financing, and decrease demand for our product.
Heightened expectations for companies to address ESG matters, including climate change, social license to operate, human rights, and governance, have a myriad of potential impacts on our business. Investors, lenders, and other stakeholders are increasingly factoring these issues into investment, financing, and business decisions, often relying on ESG ratings from third-party agencies. Unfavorable ESG ratings, coupled with growing activism around fossil fuels, could dissuade investors or lenders from engaging with us, potentially impacting our share price or access to capital across all of our operating jurisdictions (Gabon, Egypt, Cote d'Ivoire and Equatorial Guinea). Furthermore, the European Commission, in February 2025, adopted proposals to focus the Corporate Sustainability Reporting Directive (CSRD) primarily on the largest companies (those with over 1000 employees), which, while potentially easing burdens on smaller entities, reinforces the global trend towards increased sustainability reporting requirements and scrutiny for significant market participants.
While we may issue voluntary disclosures regarding ESG matters, these are often based on hypothetical expectations and assumptions that may not fully represent current or future risks, due to the inherent uncertainties, long timelines, and evolving methodologies for identifying, measuring, and reporting on many ESG topics. The approaches to climate change and the transition to a lower-carbon economy, including governmental regulations, corporate policies, and consumer behavior, are continuously evolving globally. Our operating countries, including Gabon, Egypt, Cote d'Ivoire, and Equatorial Guinea, are signatories to the Paris Agreement and are developing or implementing various climate-related strategies, NDCs, and regulations, including those aimed at reducing flaring, capping emissions, and promoting energy efficiency. We cannot reliably estimate the full impact of these evolving approaches on our financial condition, results of operations, and ability to compete.
Operational activities across our global footprint, including exploration and development, are increasingly subject to stringent social and environmental review. Certain social license risks, involving community engagement, land access, and local content requirements, are pertinent in all our operating countries and can affect our ability to obtain or renew necessary permits and approvals.
Any long-term material adverse effect on the global oil and gas industry, whether driven by climate policies, social pressures, or other ESG factors, may adversely affect our financial condition, results of operations, and cash flows. Such impacts could also arise from increased awareness and adverse publicity, restricting our access to capital or impacting the marketability of our crude oil, natural gas, and NGLs. The physical impacts of climate change, such as changes in weather patterns, sea levels, and temperatures, also pose highly uncertain but potentially significant risks to our operations in specific geographic areas. We cannot predict the full extent of how these multifaceted ESG and climate change considerations will ultimately affect us.
An increased expectation that companies address environmental (including climate change), social and governance (“ESG”) matters may have a myriad of impacts on our business. Some investors and lenders are factoring these issues into investment and financing decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from engaging with us in favor of companies in other industries, which could negatively impact our share price or our access to capital.
Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.
Approaches to climate change and the transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows.
In Canada, opposition by Indigenous groups to the conduct of our operations, development or exploratory activities in any of the jurisdictions in which we conduct business may negatively impact us in terms of public perception, diversion of management’s time and resources, legal and other advisory expenses, and could adversely impact our progress and ability to explore and develop properties.
Some Indigenous groups have established or asserted Indigenous treaty and title rights to portions of Canada. Although there are no Indigenous treaty or title rights claims on lands where we operate, no certainty exists that any lands currently unaffected by claims brought by Indigenous groups will remain unaffected by future claims. Such claims, if successful, could have a material adverse impact on our operations and pace of growth.
Canadian federal and provincial governments have a duty to consult with Indigenous people when contemplating actions that may adversely affect asserted or proven Indigenous treaty or title rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of litigation. The fulfillment of the duty to consult Indigenous people and any associated duties of accommodation may adversely affect our ability, or increase the time required to obtain or renew, permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals.
Continued development of common law precedent regarding existing laws relating to Indigenous consultation and accommodation as well as the adoption of new laws are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines that could adversely impact our progress and ability to explore and develop properties in Canada. For example, Canada is a signatory to the United Nations Declaration of the Rights of Indigenous Peoples (“UNDRIP”) and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and gas industry in Western Canada. In June 2021, the United Nations Declaration on the Rights of Indigenous Peoples Act (Canada) (“UNDRIP Act”) came into force in Canada. The UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP’s objectives. Adding further uncertainty, on June 29, 2021, the British Columbia Supreme Court issued a judgment in Yahey v British Columbia (the “Blueberry Decision”), in which it determined that the cumulative impacts of industrial development on the traditional territory of the Blueberry River First Nation (“BRFN”) in northeast British Columbia had breached BRFN’s treaty rights. The Blueberry Decision may lead to similar claims of cumulative effects across Canada in other areas covered by treaties.
In February 2025, the European Commission adopted a package of proposals to simplify EU rules and boost competitiveness. Among other things, the package proposes to apply the Corporate Sustainability Reporting Directive only to the largest companies (those with more than 1000 employees), focusing the sustainability reporting obligations on the companies which are more likely to have the biggest impacts on people and the environment. Moreover, it seeks to ensure that reporting requirements on large companies do not burden smaller companies in their value chains.
Climate change continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce the emissions of GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG emissions reporting obligations and other regulatory programs that limit or require control of GHG emissions from certain sources. These programs may limit our ability to produce crude oil, natural gas and NGLs, limit our ability to explore in new areas, or may make it more expensive to produce. In addition, these programs may reduce demand for our product either by incentivizing or mandating the use of other alternative energy sources, by prohibiting the use of our product, by requiring equipment using our product to shift to alternative energy sources, or by directly increasing the cost of fossil fuels to consumers. Additionally, in March 2024, the SEC adopted final rules intended to enhance and standardize climate-related disclosures by public companies and in public offerings;offerings. theseImmediately after the SEC’s release of the final rules, several lawsuits were filed to challenge their legality, and the rules arewere stayed pending judicial review. On March 27, 2025, the outcomeSEC ended its defense of consolidatedthe final rules on climate-related disclosures, effectively withdrawing its support for the regulation; however, the rules remain on hold pending such legal challengeschallenges, which are currently held in abeyance by the Eighth Circuit Court of Appeals.Appeals until such time as the SEC determines whether the rules will be rescinded, repealed, modified or defended in litigation.
Our operations could result in liability for personal injuries, property damage, natural resource damages, crude oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with environmental laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties and the issuance of orders enjoining operations. In addition, we could be liable for environmental damages caused by, among others, previous property owners or operators of properties that we purchase or lease. Some environmental laws provide for joint and several strict liabilityliabilities for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change and GHG and the use of hydraulic fracturing fluids, resulting in increased operating costs.
In addition, our ability to comply with the 2025 Facility Agreement's covenants could be affected by events beyond our control and we cannot assure you that we will satisfy those requirements. A prolonged period of oil and gas prices at declineddepressed levels could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. A breach of any of these provisions could result in a default under the 2025 Facility, which could allow all amounts outstanding thereunder to be declared immediately due and payable. In the event of such acceleration, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be on terms acceptable to us. We may also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the covenants under the 2025 Facility.
The borrowing base under the 2025 RBL Facility may be reduced pursuant to the terms of the 2025 Facility Agreement, which may limit our available funding for exploration and development. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.
In the future we may depend on the 2025 RBL Facility for a portion of our capital needs. The 2025 RBL Facility hashad initial aggregate commitments of $190 million and an initial borrowing base of $182 million. Subject to certain conditions, we may request, at any time prior to the date falling 30 months after the date of the 2025 Facility Agreement to increase the total commitments available under the 2025 RBL Facility byto an aggregate principal amount not to exceed $110$300 million. TheIn totaladdition, amountsubject ofto loanscertain whichconditions mayprecedent, becertain drawnexisting Lenders under the 2025 RBL Facility is limitedagreed to increase their initial commitment effective January 23, 2026 (the lower“Effective Increase Date”) so that the aggregate borrowing base under the 2025 RBL Facility as of the amountEffective ofIncrease Date increased from $190.0 million to $255.0 million. The increase in commitments was undertaken with the aggregateexisting commitmentsaccordion andfeature the Borrowing Base Amount at the relevant time. The Borrowing Base Amount is calculated pursuant to the 2025 Facility Agreement and redetermined on March 31 and September 30 of each year beginning June 30, 2025 and other interim triggers set outincluded in the 2025 FacilityRBL Agreement.Facility.
The total amount of loans which may be drawn under the 2025 Facility is limited to the lower of the amount of the aggregate commitments and the Borrowing Base Amount at the relevant time. The Borrowing Base Amount is calculated pursuant to the 2025 Facility Agreement and redetermined on March 31 and September 30 of each year beginning June 30, 2025 and other interim triggers set out in the 2025 Facility Agreement.
In the future, we may not be able to access adequate funding under the 2025 RBL Facility as a result of (i) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of the lenders to meet their funding obligations. As a result, we may be unable to obtain adequate funding under the 2025 RBL Facility. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our development plans as currently anticipated, which could have a material adverse effect on our production, revenues and results of operations.
On February 14, 2023, we announced that ourOur Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per share of common stock commencing in the first quarter of 2023. To the extent we have adequate cash on hand and cash flows from operations, we will consider continuing to pay dividends on our common stock in the future. Payment of future dividends, if any, and the establishment of future record and payment dates will be at the discretion of our 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. As a result, no assurance can be given that we will be able to continue to pay dividends to our stockholders or that the level of any future dividends will achieve a market yield or increase or even be maintained over time, any of which could materially and adversely affect the market price of our common stock.
Management's Discussion & Analysis (MD&A)
New heading “Divestment of Non-Core Assets”
New heading “Equatorial Guinea”
Largest changes
“Geopolitical Conflict and Other Market Forces – Global conflicts, including Russia’s invasion of Ukraine, conflicts in the Middle East, and heightened tensions in the Pacific region, have significantly elevated global geopolitical tensions and security concerns. Economic sanctions, export controls, and other trade restrictions, for instance those that the U.S. …”see in full comparison
“For example, in March 2024, the SEC adopted final rules under SEC Release No. 33-11275: The Enhancement and Standardization of Climate-Related Disclosures for Investors, which requires registrants to provide certain climate-related information in their registration statements and annual reports. The rules require information about a registrant’s climate-related risks that are reasonably likely to have a material impact on its business, results of operations, or financial condition. …”see in full comparison
“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. …”see in full comparison
“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. …”see in full comparison
“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. …”see in full comparison
“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. …”see in full comparison
Full comparison: every changed paragraph (95)
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 assetportfolio portfolioof production, development and exploration assets located in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea andGuinea, Nigeria, as well asas, 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.”
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.
On April 30, 2024, we completed the acquisition of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden whereby we acquired all of the issued shares in the capital of Svenska and Svenska became a direct, wholly-owned subsidiary of the Company (“Svenska Acquisition”) for a net adjusted purchase price of $40.2 million. The purchase price was funded with the Company's cash on hand. As a result of the Svenska Acquisition, we acquired Svenska’s primary asset: a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa. We also acquired a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.
We expect our 20252026 capital program to range between $270$290.0 million to $330$360.0 million, assuming normal operating conditions, thatwhich prioritizes free cash flow generation and meaningful return of capital to shareholders. The program includes estimated spending of approximately between $115$110.0 million to $135$135.0 million for Gabon, $30$9.0 million to $40$12.0 million for Egypt, $8$0.5 million to $13 million for Canada, $1 million to $3$1.5 million for Equatorial Guinea, $115$170.0 million to $135$210.0 million for Cote d'Ivoire for oil and natural gas development and $1$0.5 to $1.5 million related to corporate and other capital costs. The foregoing amounts related to Etame projects in Gabon do not include amounts funded by the non-operating partners. See further discussion below under “Capital Resources, Liquidity and Cash Requirements” for further discussion on the capital spending for each of our operating segments.
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 delivery of drilling and production equipment, particularly if suppliers adjust pricing in response to increased duties or if we are required to diversify sourcing channels. These impacts could affect the timing, cost structure and execution risk of certain development activities, especially in frontier offshore environments.
Additionally, the evolving global trade environment may increase compliance complexity and affect the cost efficiency of international operations. Enhanced documentation requirements and new rules of origin associated with U.S. trade actions could impact our ability to efficiently move materials through international logistics hubs, such as those in Houston, Texas and could necessitate additional internal resources to maintain compliance. These complexities necessitate additional internal resources to ensure sustained compliance and efficient material flow.
The broader geopolitical trade environment, including retaliatory tariffs and ongoing trade tensions with key partners, continues to inject volatility into the global supply network, necessitating vigilant risk management and strategic sourcing to mitigate operational disruptions and cost impacts.
Enactment of the One Big Beautiful Bill Act of 2025 – On July 4, 2025, the budget reconciliation bill known as the One Big Beautiful Bill Act of 2025 (“OBBBA”) was signed into law, which includes significant changes to federal tax law and other regulatory provisions that may impact the Company. Among other provisions, the OBBBA makes permanent key elements of the Tax Cuts and Jobs Act of 2017. The legislation has multiple effective dates, with certain provisions effective in 2025 and others implemented through 2027. The impact of provisions effective in 2025 are not material and the Company is still assessing the impact of provisions that are not yet effective.
Moreover, to the extent U.S. policy shifts create uncertainty in bilateral relations or disrupt traditional trade partnerships, there could be indirect effects on our ability to manage risk and maintain favorable operating conditions in host countries. While we continue to monitor the evolving regulatory and trade landscape, we cannot predict the full impact of current or future tariffs, trade restrictions or retaliatory actions on our operations, financial condition or future capital deployment decisions.
Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC. In addition, recent U.S. energy policy changes that prioritize domestic production and energy security, including through tax credits and development incentives, may influence global supply dynamics and capital flows, potentially altering the competitive landscape for international assets.
ESG and Climate Change Effects – Sustainability matters continue to attract public, political, regulatory and scientific attention.
While 2025 has seen a deceleration in the adoption of sustainability-oriented regulation, particularly in the U.S., and a noticeable shift by some financial institutions away from explicitly “ESG” or “Net Zero” branded initiatives due to perceived political or reputational sensitivities, we believe the underlying trend of focusing on sustainability remains consistent. Long-term structural pressures, including stakeholder expectations, evolving global market standards, and transition-related investment priorities, continue to support the integration of sustainability considerations into corporate strategy and capital markets.
The attention to climate change and environmental stewardship coupled with increasing government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against the oil and gas industry, including Vaalco. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, voluntary efforts to reduce routine flaring, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries.
Climate-Related Disclosures – On March 27, 2025, the SEC ended its defense of the final rules on climate-related disclosures, effectively withdrawing its support for the regulation. The rules, which were adopted in March 2024, require publicly traded companies to disclose climate-related risks and greenhouse gas emissions. The SEC's decision to end its defense was made after a change in administration and a shift in policy, with Acting Chairman Mark Uyeda expressing concerns about the rule's costs and intrusiveness. While the rules remain on hold pending legal challenges, which, as of September 2025, have been held in abeyance by the Eighth Circuit Court of Appeals until such time as the SEC reconsiders the challenged rules by notice-and-comment rulemaking or renews its defense of the rules, the SEC's withdrawal of support signals a potential shift in direction for climate disclosure regulations. Despite this regulatory shift in the U.S., we remain committed to maintaining transparency and aligning with industry standards for similarly situated companies.
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.
We reported a net incomeloss for the year ended December 31, 20242025 of $58.5$41.4 million compared to a net income of $60.4$58.5 million for the year ended December 31, 2023.2024. The year-over-year decrease in net income was due primarily to higheran 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, productioncredit expenseslosses and creditincome lossestax expense during the year,current partially offset by the increase in revenues and a bargain purchase gain related to the Svenska acquisition. Further discussion of results by significant line item follows.year.
Further discussion of results by significant line item follows.
The revenue changes between the years ended December 31, 2024 and 2023 identified as related to changes in price or volume are shown in the table below:
(1)The Other in the table above includes revenues attributed to carried interests.
The table below shows net production, sales volumes and realized prices for both years.
Crude oil, natural gas and NGLs net revenues increaseddecreased $23.9$119.7 million, or approximately 5%,25%, during the year ended December 31, 20242025 compared to the same period of 2023.2024. The revenue increasedecrease is primarily attributable to lower revenues recognized within the Cote d'Ivoire segment during the year ended December 31, 2024 that were not present in theGabon priorand period.Côte d’Ivoire.
Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $206.0$181.7 million of revenue to the Company’s total revenue during the year ended December 31, 2024.2025, Thiswhich comparesis tolower than the $260.3$206.0 million of revenue contributed by the segment duringin the year ended December 31, 2023.2024. The decrease in revenues is primarily due to lower sales volume in Gabon. The total sales volume in Gabon for the year ended December 31, 2024 was 2,584 MBbls or 612 MBbls lower than the sales volumes of 3,196 MBbls in the same period in 2023. Further, we had a decrease in the Gabon average realized price per barrel received during the year ended December 31, 20242025 of $78.81$65.76 per barrel (Bbl) compared to the price received in 20232024 of $79.80$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 267,75467 barrelsMBbls and 68,766268 barrelsMBbls at December 31, 20242025 and 2023,2024, respectively.
Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. The Company’s Egypt segment contributed $146.0$140.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024.2025 This comparescompared to the $161.0$146.0 million of revenue contributed by the segment duringin the year ended December 31, 2023.2024. The decrease in revenues was primarily due to a lower average realized price received in Egypt of $51.27 per Bbl during the decreaseyear 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, 20242025 to 2,5852,730 MBbls compared to 2,7712,585 MBbls during the same period in 2023.2024. The average realized price received in Egypt was $56.47 per Bbl during the year ended December 31, 2024, which was also lower compared to the $58.11 per barrel received in 2023. At December 31, 2024, the Company’s Egypt segment had zero barrels inno oil inventory.inventory at December 31, 2025.
CrudePrior to the Canada Asset Divestment, crude oil sales in Canada arewere normally sold through pipelines to a third party. The Company’s Canadian segment contributed $32.0$19.2 million of revenue to the Company’s total revenue for the year ended December 31, 2024.2025, Thisa comparesdecrease tofrom the $33.7$32.0 million of revenue contributed by the Canada Segment duringin the year ended December 31, 2023.2024. The decrease in revenues is due to the lower average realized sales price received during the year ended December 31, 20242025 of $36.77$28.74 per MBoe or a decrease of $1.79$8.03 per Boe from the $38.92$36.77 per Boe received during the same period in 2023.2024. TheIn addition, there was a decrease in the average realized price was offset by the increase in sales volumes during the same period. In Canada, the total sales volumes for the year ended December 31, 20242025 wasto 870667 MBoe or 5 MBoe higher thanfrom the 865870 MBoe sold during the yearsame endedperiod in 2024 which contributed to the decrease in revenues. The Company’s Canadian segment had no oil inventory at December 31, 2023.2025.
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.
Crude oil sales in Cote d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world. The Company's Cote d’Ivoire Segment contributed $95.1 million of revenue to the Company’s total revenue during the year ended December 31, 2024. Total sales volumes in Cote d'Ivoire for the year ended December 31, 2024 was 1,223 MBbls and the average realized sales price received was $77.74 per barrel.
Production expenses increaseddecreased $10.3$5.3 million, or approximately 7%,3%, to $163.5$158.2 million in the year ended December 31, 20242025 compared to the same period of 2023.2024. The increasedecrease in production expense was primarily driven by thea crude oil inventory acquiredreduction in theproduction Svenska Acquisition that was recorded at fair value upon acquisition and lower of cost or net realizable valueexpenses in subsequentour periods.Côte Ind’Ivoire addition,segment VAALCOpartially hasoffset seen inflationary pressure on personnel and contractor costs. In February 2024, the government in Gabon enacted new regulation which has resulted inby an increase toin withholdingexpenses taxesin onour foreignGabon supplied goods and services.segment. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 20242025 decreasedincreased to $24.78 per barrel from $22.48 per barrel fromfor 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 of $22.59 per barrel primarily as a result of higher production volumes for the current period.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.
FPSO demobilization costs decreased $7.5 million, or 100%, to zero in the year ended December 31, 2024 compared to the same period of 2023. In 2023, it was determined that there was additional normally occurring radioactive material (NORMs) waste than anticipated connected to the FPSO from the Contractors' usage. As such, VAALCO and JOA partners incurred an additional $7.5 million (net to VAALCO) in decommissioning fees, which was reported as a separate line item on the income statement. These costs were incurred to retire the FPSO as we transitioned the Etame block to the FSO.
Exploration expenses decreased $1.9 million, or approximately 98%, in the year ended December 31, 2024 compared to the same period of 2023 due primarily to the abandonment of the Egyptian East Arta - 54 appraisal well and the abandonment of the NWG-5C1 appraisal well in 2023.
Depreciation, depletion and amortization increaseddecreased $27.7$33.1 million, or approximately 24%,23%, to $110.0 million in the year ended December 31, 20242025 compared to the same period of 2023.2024. The increasedecrease in depreciation, depletion and amortization expense is due primarily to theno additionproduction ofin CoteCôte d'Ivoired’Ivoire relatedsince toJanuary 2025 when the SvenskaFPSO Acquisitionwent partially offset by lower depletable costs in Gabon, Egypt, and Canada.offline.
General and administrative expenses increased $5.8$3.4 million, or approximately 25%,11%, to $33.1 million in the year ended December 31, 20242025 compared to the same period of 2023.2024. The increase in general and administrative expenses is primarily due to professionalan fees,increase accountingin andstock legalbased services, andcompensation, salaries and wages.wages, and professional service fees.
Credit loss and other allowances - Credit loss and other expense increaseddecreased $11.2$6.2 million, or approximately 228%,98%, to $0.1 million in the year ended December 31, 20242025 compared to the same period of 2023.2024. The increase in credit losses and other for the year ended December 31, 2024,2024 iswas primarily attributable to the receivableshigher withallowance EGPCcalculated regardingduring the2024 settlement of these receivables owedrelated to the Company.Egypt DuringBackdated Receivables, defined in Part IV, Item 15., Note 11. Commitments and Contingencies to the yearConsolidated endedFinancial DecemberStatements. The Backdated Receivables were settled as of March 31, 2023,2025, while the decreaseremaining intrade creditreceivables lossare current and othertherefore allowancesit was primarilydetermined duethat tono twoprovision creditwas loss and other allowance reversals in 2023. These two reversals were partially offset by a credit loss and other allowance adjustment in Egypt.required.
Derivative instruments gain (loss), net is attributable to our commodity instruments as discussed in Part IV, Item 15., Note 10.9. Derivatives and Fair Value to the Consolidated Financial Statements. During the years ended December 31, 20242025 and 2023,2024, we recognized net realized losses of $0.5less than $0.1 million and $0.1$0.5 million, respectively, and unrealized losses of $0.2 million and an unrealized gain of $0.4$2.9 million and an unrealized loss of $0.2 million, respectively, or a total net derivative lossesgain of $0.7$2.9 million and a total net derivative gainloss of $0.2$0.7 million, respectively. Derivative lossesgains for 20242025 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the year ended December 31, 2024.2025. Our derivative instruments currently cover a portion of our production through SeptemberMarch 2025.2027 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 decreasedincreased $2.7$4.5 million to an expense of $3.7$8.2 million for the year ended December 31, 20242025 from an expense of $6.5$3.7 million during the same period in 2023.2024. The decreaseincrease of net interest expense for the year ended December 31, 20242025 primarily resultsresulted from aan decreaseincrease in our amortization of debt issue costs andcosts, commitment fees incurred and interest incurred on our borrowing under the 2025 RBL FacilityFacility, 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 increaseddecreased $4.9$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 from an expense of $0.9 million for the year ended December 31, 2023.2024. 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, 20242025 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.million Thiswhich is comprised of $98.9 million of current tax expense and a deferred tax benefit of $17.6 million. Income tax expense for the year ended December 31, 2023 was an expense of $89.7 million. This was comprised of $92.6 million of current tax expense and a deferred tax benefit of $2.9 million. 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 higherlower in 20242025 than the income tax forexpense thein comparable 20232024 period as a result of higherlower revenues. See Part IV, Item 15., Note 8.7. Income Taxes to the Consolidated Financial Statements for further discussion.
During 2024,2025, we had accrual basis expenditures attributable to operations of $109.4$236.4 million, that includes $22.6$61.7 million for Gabon, $11.4$28.8 million for Egypt, $25.8$1.6 million for Canada, $44.4$143.2 million for Cote d'Ivoire, $0.6 million for Equatorial Guinea and $4.6$0.5 million for the corporate offices, compared to $72.6$109.4 million for 2023.2024. Capital expenditures in 20242025 were attributable to expenditures primarily related to the new wells drilled as part of the drilling campaign in Canada,Egypt, the workoverPhase andThree drilling program in EgyptGabon, andas thewell as expenditures associated with the preparationrefurbishment of the FPSO dryin dockCôte projectd'Ivoire. During the same period in Cote2024, d'Ivoire.our Capitalcash expenditures in 2023 werespending primarily related to the Svenska acquisition as well as payments for the 20232024 drilling campaigns in both Egypt and Canada.
The Company’s Phase Three Drilling Program in Gabon commenced in the fourth quarter of 2025 with the drilling of the Etame 15H-ST1 development well in the 1V block of Etame in December 2025. The well was completed and placed on production in January 2026 confirming expectations from the pilot well results. Although the West Etame exploration well (ET-14P) encountered 10 meters of high quality sands, the target zone was water-bearing. The lower portion of the well will be plugged and abandoned but the well bore will be utilized and sidetracked in the upper portion of the well to drill the ET-14H development well in the Main Fault Block of Etame. Operations are expected to be completed in April.
After completing our program at the Etame platform, we expect to move the drill rig to the SEENT and Ebouri platforms where we have several wells and workovers planned to enhance production and potentially add reserves.
In July 2025, the Company performed planned, staged shutdowns of the Gabon platforms to perform safety inspections and necessary maintenance to increase the integrity and reliability of the assets. This is the first full field maintenance shutdown that the Company has performed since the new Floating Storage and Offloading vessel (“FSO”) was brought online in 2022. All fields were successfully brought back online and the planned turnaround was completed on budget and with no safety or environmental incidents.
The BWE Consortium initiated its 3D seismic campaign across the Niosi and Guduma blocks in November 2025 and such campaign was completed in January 2026. The seismic acquisition was executed and satisfies the minimum commitments under the terms of the Niosi PSC as well as to inform the decision on proceeding into the second exploration period for the Guduma Block.
The drilling campaign in Egypt began in December 2024 and continued throughout 2025. During 2025, we drilled a total of 16 wells in the Eastern Dessert, which included 16 development wells. In December 2025, we started drilling an additional well which was completed in January 2026. All wells drilled in the Eastern Dessert successfully achieved their target. Additionally, continuous well interventions, workovers and optimization activities were carried out in 2025 to enhance production levels. We also drilled one exploration well in South Ghazalat which was later determined to be not commercially viable.
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.
In 2025, the Company decided to defer the drilling of additional wells in Canada based on a reassessment of capital allocation priorities across the portfolio and to ensure that investment is directed toward projects with the highest expected returns. As discussed above, in early 2026, the Company completely exited its Canadian oil and gas operations. Please see above under “Divestment of Non-Core Assets,” for further discussion on the sale of the Canada operating assets.
Equatorial Guinea
We own a 60% working interest in an undeveloped portion of Block P offshore Equatorial Guinea where we are the designated operator. We have an existing plan of development of the Venus field discovery on Block P, which focuses on key areas of drilling evaluations, facilities design, market inquiries and metocean review. In the second quarter of 2025, the Company completed the initial Front End Engineering and Design study that confirmed the viability of the development concept and is currently evaluating alternative technical solutions which may deliver enhanced economic value.
The Company secured a drilling rig in December 2024 in conjunction with its 2025/2026 drilling program, which is planned to begin in mid-2025 to drill multiple development wells, and appraisal or exploration wells, as well as to perform workovers, with options to drill additional wells. We are planning on multiple wells in both the Etame field and at our SEENT platform, and a re-drill and several workovers in the Ebouri field to access production and reserves that were previously shut in and removed from proved reserves due to the presence of hydrogen sulfide.
The Company focused on enhancing production in 2024 through a series of planned workovers. The EA-55 well, drilled in October 2023, was completed and put online in January 2024. During the year, the planned workover program for 2024 was completed for 12 wells, including the K-81 well recompletion at the start of the first quarter of 2024, which was a carry-over from our 2023 drilling activity. The focus of the workover activities was to achieve peak production from the wells, significant improvements on the rate of production, and enhance production efficiency.
What changed in the latest 10-Q
Risk Factors
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.
No wording changes found in this section.
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Management's Discussion & Analysis (MD&A)
New heading “Crude oil, natural gas and NGLs revenues:”
New heading “Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025”
Removed heading “RECENT DEVELOPMENTS”
Removed heading “Canada Assets Divestment”
Removed heading “Assumption of Operatorship”
Removed heading “Capital Expenditures”
Removed heading “Capital Resources, Liquidity and Cash Requirements”
Largest changes
“Capital Resources, Liquidity and Cash Requirements”see in full comparison
“Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025”see in full comparison
“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. …”see in full comparison
“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 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. …”see in full comparison
“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. …”see in full comparison
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•the ability of the FPSO in Cote d’Ivoire to return to service within the expected timeframe;
•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 RussianRussia/Ukraine invasion of Ukraine,war, 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;
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,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,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.
Vaalco is a Houston, Texas-based, African-focused independent energy company with a strong production and reserve portfolio of assets in Gabon, Egypt, Côte d'Ivoire,d’Ivoire, Equatorial Guinea, Nigeria, as well as,and, 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.
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 warwar, Unitedconflicts States-Israel-Hamasin conflict,the Middle East, including the 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, and 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 turnturn, 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. basedU.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. alignedU.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,filing areis 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 several 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.
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.
We successfully drilled and completed the Ebouri-5H development well as part of our ongoing Phase Three Drilling Program, with production commencing in June 2026. Following the completion of operations at the Ebouri platform, the drilling rig was mobilized to the SEENT platform where we spudded the ETBNM-3 gas-supply well. The well is planned as a directionally drilled slant well adjacent to a discovery well and is targeting gas and condensate resources in the Dentale D15 reservoir. The well was successfully brought online and the natural gas produced from this successful well is now being utilized for operational purposes in the field to significantly reduce the costs of higher priced diesel that is currently transported to the field by vessel. We also commenced drilling a second development well at the SEENT platform in late July 2026. Through the remainder of the Phase Three Drilling Program, our objective is to continue growing production volumes and adding proved reserves through the successful execution of our development program.
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.
TheIn addition, 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.
The 2026 Egypt drilling program commenced in May 2026 with the drilling of the HE-9 development well, which was completed and brought on production in early June 2026. We subsequently initiated drilling of two additional development wells in June 2026, both of which were successfully completed in July 2026. We are continuing with our drilling program in Egypt in the third quarter of 2026.
We also successfully executed a series of workovers, well interventions, well reactivations, water shut-off treatments, and production optimization activities that are contributing to the organic growth of our production and reserves.
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
TheFollowing Baobabthe FPSOcompletion completedof its planned dry dock refurbishment in February 20262026, the Baobab FPSO returned to Côte d’Ivoire and arrivedwas backsuccessfully inreconnected Côteto d'Ivoirefield infrastructure in early April 2026. ReconnectionProduction activitiesresumed arefrom nowall underwayproducer wells in June 2026. While production has restarted, the first crude oil lifting is scheduled for August 2026. A drilling rig has been mobilized and fieldthe productiondrilling program is expected to restartstart duringin the second quarter ofSeptember 2026. A rig has been secured for the plannedThis development drilling program which is expected to begin at the end of the third quarter of 2026. The drilling campaign is expected to bringdrive meaningful additions to production fromgrowth and further unlock the value of the main Baobab field in blockBlock CI-40.
The Company is also the operator of exploration license CI-705 with a 70% working interest. Currently in the first exploration period, subsurface interpretation and prospect maturation continues with the Company and its partners scheduled to make the decision whether to enter into the second phase of the exploration period by year-end 2026.
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 tobeing beactively completedprogressed toward completion in the secondfirst half of 2026.2027.
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. Work is progressing towards Final Investment Decision in the fourth quarter of 2026.
As discussed above, in February 2026, the Company completely exited its Canadian oil and gas operations. Please see abovePart underI, “CanadaItem Assets1, Divestment,”Note 3. Acquisition and Disposition to the unaudited condensed consolidated financial statements for further discussion on the sale of the Canada operating assets.
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 June 30, 2026, we had unrestricted cash of $30.4 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 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, or other strategic transactions depends on operating and economic conditions, some of which are beyond our control. In the event additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, on expected timelines, or at all. We continue to evaluate the use of available cash, including opportunistic acquisitions and other growth initiatives, and assess whether additional liquidity sources, including equity and/or debt financing, would be appropriate to fund such activities.
Our cash flows for the threesix months ended MarchJune 31,30, 2026 and 2025 are as follows:
The $71.9$16.6 million decrease in net cash provided by operating activities during the threesix months ended MarchJune 31,30, 2026 compared to the threesix months ended MarchJune 31,30, 2025 was primarily dueattributable to lowercash settlements paid on matured derivative contracts and higher exploration expenses, including the acquisition of seismic data and costs associated with an unsuccessful well. These decreases were partially offset by higher crude oil, natural gas and natural gas liquids sales ($47.7 million) and anfavorable increase in net cash usedchanges in working capital and other assets and liabilities ($33.6 million).liabilities.
Net cash used in investing activities during the threesix months ended MarchJune 31,30, 2026 was primarily attributable to $78.1$181.6 million for costsexpenditures associated with the Baobab FPSO refurbishment work and reconnection activities, as well as the development drilling programs in Gabon, as well as maintenance, project costs and long lead items for Gabon and Côte d’Ivoire,Egypt, offset by cash proceeds of $25.5 million from the Canada Assets Divestment. For the threesix months ended MarchJune 31,30, 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.d’Ivoire.
Net cash provided by financing activities during the threesix months ended MarchJune 31,30, 2026 primarily consistsconsisted of $92.0$117.0 million inof proceeds from borrowings under the 2025 RBL Facility, offset by cash usedoutflows of $6.7$13.4 million for dividend distributions, $1.2$2.2 million for deferred financing costs, $2.0 million to satisfy employee withholding tax obligations related to vested equity awards, and $6.2 million of principal payments on finance lease obligations. For the six months ended June 30, 2025, cash used in financing activities primarily included $13.1 million for dividend distributions, $6.9 million of payments for deferred financing costs and $3.2$6.3 million of principal payments on our finance leases.leases, Foroffset by $60.0 million in proceeds from borrowing under the three2025 monthsRBL 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.Facility.
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.
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.
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.
We actively manage commodity price risk by entering into derivative transactions that help mitigate the impact of volatility in crude oil, NGL and natural gas prices on our cash flows and operating results; however, these transactions may also limit our cash flow in periods of rising crude oil, NGL and natural gas prices. We have entered into derivative contracts primarily with counterparties that are also lenders under the 2025 RBL Facility. 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.
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.
Our material cash requirements generally consist of thecapital FPSO refurbishment and reconnection,projects, finance and operating leases, capital projects, dividend payments, Merged Concession Agreement and abandonment funding, each of which is discussed in further detail below.
Capital Projects and Expenditures - For the six months ended June 30, 2026, we had accrual basis capital expenditures of $172.4 million compared to $92.2 million accrual basis capital expenditures for the same period in 2025. Capital spending during the six-month period ended June 30, 2026, primarily reflected development activities associated with the Phase Three drilling campaign in Gabon, refurbishment and reconnection activities relating to the FPSO in Côte d’Ivoire, expenditures associated with an unsuccessful exploration well in Gabon and costs incurred in connection with the 3D seismic campaign across the Niosi and Guduma blocks.
See “Recent Operational Updates” above for additional information regarding our capital projects.
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 MarchJune 31,30, 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.
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 alsowe have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on theFebruary Merged1, 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.2020. Through MarchJune 31,30, 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. See Part I, Item 1, Note 9. Commitments and Contingencies to the unaudited condensed consolidated financial statements for additional information.
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 hashave 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- D3D 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.
The Company paid a quarterly cash dividend of $0.0625 per share of common stock for the second quarter of 2026 ($0.25 annualized) on June 26, 2026 to stockholders of record at the close of business on May 22, 2026. The Company also announced its next quarterly cash dividend of $0.0625 per share of common stock for the third quarter of 2026 ($0.25 annualized) to be paid on September 22, 2026 to stockholders of record at the close of business on August 21, 2026.
Three Months Ended MarchJune 31,30, 2026 Compared to the Three Months Ended MarchJune 31,30, 2025
Net lossincome for the three months ended MarchJune 31,30, 2026 was $93.8$42.4 million compared to a net income of $7.7$8.4 million during the same period ofin 2025. See discussion below for changes in revenues and expenses.
Crude oil, natural gas and NGLs revenues decreasedincreased $47.7$38.3 million, or approximately 43%,40%, to $62.6$135.2 million during the three months ended MarchJune 31,30, 2026 from $110.3$96.9 million during the same period in 2025. The increase in revenue decrease is primarily dueattributable to lowerhigher revenuesrealized sales prices per barrel, partially offset by a slight decline in Gabon,sales Côte d’Ivoire and Canada.volumes.
EGY insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 0 filings. Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-06-08 | Pruckl Thor |
Shares withheld for tax | 2,906 | $5.53 | $16.1K |
| 2026-06-08 | Pruckl Thor |
Shares withheld for tax | 5,575 | $5.53 | $30.8K |
| 2026-06-08 | Powers Matthew R |
Shares withheld for tax | 1,696 | $5.53 | $9.4K |
| 2026-06-08 | Powers Matthew R |
Shares withheld for tax | 2,846 | $5.53 | $15.7K |
| 2026-06-08 | Willis Lynn |
Shares withheld for tax | 1,356 | $5.53 | $7.5K |
| 2026-06-08 | Bain Ronald Y |
Shares withheld for tax | 8,612 | $5.53 | $47.6K |
| 2026-06-08 | Bain Ronald Y |
Shares withheld for tax | 5,967 | $5.53 | $33.0K |
| 2026-06-08 | Maxwell George W.m. |
Shares withheld for tax | 23,525 | $5.53 | $130.1K |
| 2026-06-08 | Maxwell George W.m. |
Shares withheld for tax | 16,409 | $5.53 | $90.7K |
| 2026-06-05 | Donohue Casey |
Shares withheld for tax | 4,873 | $5.29 | $25.8K |
| 2026-06-05 | Powers Matthew R |
Shares withheld for tax | 12,340 | $5.29 | $65.3K |
| 2026-06-05 | Maxwell George W.m. |
Shares withheld for tax | 100,540 | $5.29 | $531.9K |
| 2026-06-05 | Willis Lynn |
Shares withheld for tax | 2,586 | $5.29 | $13.7K |
| 2026-06-05 | Pruckl Thor |
Shares withheld for tax | 24,168 | $5.29 | $127.8K |
| 2026-06-05 | Bain Ronald Y |
Shares withheld for tax | 37,335 | $5.29 | $197.5K |
| 2026-06-04 | Powers Matthew R |
Grant/award | 25,893 | — | — |
| 2026-06-04 | Powers Matthew R |
Grant/award | 18,484 | — | — |
| 2026-06-04 | Pruckl Thor |
Grant/award | 44,387 | — | — |
| 2026-06-04 | Pruckl Thor |
Grant/award | 31,686 | — | — |
| 2026-06-04 | Stubbs Catherine L |
Grant/award | 23,173 | — | — |
| 2026-06-04 | Willis Lynn |
Grant/award | 19,935 | — | — |
| 2026-06-04 | Bain Ronald Y |
Grant/award | 101,500 | — | — |
| 2026-06-04 | Bain Ronald Y |
Grant/award | 72,456 | — | — |
| 2026-06-04 | Donohue Casey |
Grant/award | 21,528 | — | — |
| 2026-06-04 | Donohue Casey |
Grant/award | 15,368 | — | — |
| 2026-06-04 | Fawthrop Andrew Lawrence |
Grant/award | 23,173 | — | — |
| 2026-06-04 | Lafehr Edward David |
Grant/award | 23,173 | — | — |
| 2026-06-04 | Maxwell George W.m. |
Grant/award | 211,945 | — | — |
| 2026-06-04 | Maxwell George W.m. |
Grant/award | 151,297 | — | — |
| 2026-06-04 | Nze-Bekale Fabrice |
Grant/award | 23,173 | — | — |
Well-known investors holding EGY (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| Renaissance Technologies | 2026-06-30 | 1,181,526 | $6.0M | 0.01% | Reduced 9% |
| D. E. Shaw & Co. | 2026-06-30 | 182,125 | $925.2K | 0.0% | Added 145% |
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 116,513 | $591.9K | 0.0% | Reduced 53% |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 84,811 | $430.8K | 0.0% | New position |
| Millennium Management (Israel Englander) | 2026-06-30 | 75,470 | $383.4K | 0.0% | Reduced 74% |
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 40,989 | $259.9K | — | Sold out |
| Two Sigma Investments | 2026-06-30 | 27,641 | $140.4K | 0.0% | Reduced 58% |