VAALCO ENERGY INC /DE/ (EGY) FY 2024 MD&A

INTRODUCTION

We are an independent energy company headquartered in Houston, Texas engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs. We have a diversified African-focused asset portfolio in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea and Nigeria, as well as producing properties in Canada. For further discussion of our five operating segments see “Item 1. Business – Segment and Geographical Information.”

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

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

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

Recent Developments and Outlook

2024 Acquisition

On April 30, 2024, we completed the acquisition of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden whereby we acquired all of the issued shares in the capital of Svenska and Svenska became a direct, wholly-owned subsidiary of the Company (“Svenska Acquisition”) for a net adjusted purchase price of $40.2 million. The purchase price was funded with the Company's cash on hand. As a result of the Svenska Acquisition, we acquired Svenska’s primary asset: a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa. We also acquired a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.

Capital Program

We expect our 2025 capital program to range between $270 million to $330 million, assuming normal operating conditions, that prioritizes free cash flow generation and meaningful return of capital to shareholders. The program includes estimated spending of approximately between $115 million to $135 million for Gabon, $30 million to $40 million for Egypt, $8 million to $13 million for Canada, $1 million to $3 million for Equatorial Guinea, $115 million to $135 million for Cote d'Ivoire for oil and natural gas development and $1 million related to corporate and other capital costs. 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.

Commodity Prices

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

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RESULTS OF OPERATIONS

Year Ended December 31, 2024 Compared to Year Ended December 31, 2023

We reported net income for the year ended December 31, 2024 of $58.5 million compared to a net income of $60.4 million for the year ended December 31, 2023. The year-over-year decrease in net income was due to higher depreciation, depletion and amortization expense, production expenses and credit losses during the year, partially offset by the increase in revenues and a bargain purchase gain related to the Svenska acquisition. 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.

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

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Crude oil, natural gas and NGLs net revenues increased $23.9 million, or approximately 5%, during the year ended December 31, 2024 compared to the same period of 2023. The revenue increase is primarily attributable to revenues recognized within the Cote d'Ivoire segment during the year ended December 31, 2024 that were not present in the prior period.

Gabon

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year. The Company’s Gabon segment contributed $206.0 million of revenue to the Company’s total revenue during the year ended December 31, 2024. This compares to the $260.3 million of revenue contributed by the segment during the year ended December 31, 2023. The decrease in revenues is primarily due to lower sales volume in Gabon. The total sales volume in Gabon for the year ended December 31, 2024 was 2,584 MBbls or 612 MBbls lower than the sales volumes of 3,196 MBbls in the same period in 2023. Further, we had a decrease in the Gabon average realized price per barrel received during the year ended December 31, 2024 of $78.81 per barrel (Bbl) compared to the price received in 2023 of $79.80 per Bbl. Our share of crude oil inventory, excluding royalty barrels, was approximately 267,754 barrels and 68,766 barrels at December 31, 2024 and 2023, respectively.

Egypt

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC. The Company’s Egypt segment contributed $146.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024. This compares to the $161.0 million of revenue contributed by the segment during the year ended December 31, 2023. The decrease in revenues was primarily due to the decrease in sales volumes during the year ended December 31, 2024 to 2,585 MBbls compared to 2,771 MBbls during the same period in 2023. The average realized price received in Egypt was $56.47 per Bbl during the year ended December 31, 2024, which was also lower compared to the $58.11 per barrel received in 2023. At December 31, 2024, the Company’s Egypt segment had zero barrels in oil inventory.

Canada

Crude oil sales in Canada are normally sold through pipelines to a third party. The Company’s Canadian segment contributed $32.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024. This compares to the $33.7 million of revenue contributed by the Canada Segment during the year ended December 31, 2023. The decrease in revenues is due to the lower average realized sales price received during the year ended December 31, 2024 of $36.77 per MBoe or a decrease of $1.79 per Boe from the $38.92 per Boe received during the same period in 2023. The decrease in the average realized price was offset by the increase in sales volumes during the same period. In Canada, the total sales volumes for the year ended December 31, 2024 was 870 MBoe or 5 MBoe higher than the 865 MBoe sold during the year ended December 31, 2023.

Cote d'Ivoire

Crude oil sales in Cote d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world. The Company's Cote d’Ivoire Segment contributed $95.1 million of revenue to the Company’s total revenue during the year ended December 31, 2024. Total sales volumes in Cote d'Ivoire for the year ended December 31, 2024 was 1,223 MBbls and the average realized sales price received was $77.74 per barrel.

Production expenses increased $10.3 million, or approximately 7%, to $163.5 million in the year ended December 31, 2024 compared to the same period of 2023. The increase in production expense was primarily driven by the crude oil inventory acquired in the Svenska Acquisition that was recorded at fair value upon acquisition and lower of cost or net realizable value in subsequent periods. In addition, VAALCO has seen inflationary pressure on personnel and contractor

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costs. In February 2024, the government in Gabon enacted new regulation which has resulted in an increase to withholding taxes on foreign supplied goods and services. On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 2024 decreased to $22.48 per barrel from the prior year of $22.59 per barrel primarily as a result of higher production volumes for the current period.

FPSO demobilization costs decreased $7.5 million, or 100%, to zero in the year ended December 31, 2024 compared to the same period of 2023. In 2023, it was determined that there was additional normally occurring radioactive material (NORMs) waste than anticipated connected to the FPSO from the Contractors' usage. As such, VAALCO and JOA partners incurred an additional $7.5 million (net to VAALCO) in decommissioning fees, which was reported as a separate line item on the income statement. These costs were incurred to retire the FPSO as we transitioned the Etame block to the FSO.

Exploration 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 increased $27.7 million, or approximately 24%, in the year ended December 31, 2024 compared to the same period of 2023. The increase in depreciation, depletion and amortization expense is due primarily to the addition of Cote d'Ivoire related to the Svenska Acquisition partially offset by lower depletable costs in Gabon, Egypt, and Canada.

General and administrative expenses increased $5.8 million, or approximately 25%, in the year ended December 31, 2024 compared to the same period of 2023. The increase in general and administrative expenses is primarily due to professional fees, accounting and legal services, and salaries and wages.

Credit loss and other allowances - Credit loss and other expense increased $11.2 million, or approximately 228%, in the year ended December 31, 2024 compared to the same period of 2023. The increase in credit losses and other for the year ended December 31, 2024, is primarily attributable to the receivables with EGPC regarding the settlement of these receivables owed to the Company. During the year ended December 31, 2023, the decrease in credit loss and other allowances was primarily due to two credit loss and other allowance reversals in 2023. These two reversals were partially offset by a credit loss and other allowance adjustment in Egypt.

Derivative instruments gain (loss), net is attributable to our commodity instruments as discussed in Part IV, Item 15., Note 10. Derivatives and Fair Value to the Consolidated Financial Statements. During the years ended December 31, 2024 and 2023, we recognized net realized losses of $0.5 million and $0.1 million, respectively, and unrealized losses of $0.2 million and an unrealized gain of $0.4 million, respectively, or a total net derivative losses of $0.7 million and net derivative gain of $0.2 million, respectively. Derivative losses for 2024 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the year ended December 31, 2024. Our derivative instruments currently cover a portion of our production through September 2025.

Interest (expense) income, net decreased $2.7 million to an expense of $3.7 million for the year ended December 31, 2024 from an expense of $6.5 million during the same period in 2023. The decrease of net interest expense for the year ended December 31, 2024 primarily results from a decrease in our amortization of debt issue costs and commitment fees incurred on the RBL Facility partially offset by interest income.

Other (expense) income, net increased $4.9 million to an expense of $5.8 million for the year ended December 31, 2024 from an expense of $0.9 million for the year ended December 31, 2023. 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, 2024 was an expense of $81.3 million. This is comprised of $98.9 million of current tax expense and a deferred tax benefit of $17.6 million. Income tax expense for the year ended December 31, 2023 was an expense of $89.7 million. This was comprised of $92.6 million of current tax expense and a deferred tax benefit of $2.9 million. The current tax expense in both periods is primarily attributable to our operations in Gabon, Egypt, Canada and Cote d'Ivoire. The income tax expense is higher in 2024 than income tax for the comparable 2023 period as a result of higher revenues. See Part IV, Item 15., Note 8. Income Taxes to the Consolidated Financial Statements for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

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Capital Expenditures

During 2024, we had accrual basis expenditures attributable to operations of $109.4 million, that includes $22.6 million for Gabon, $11.4 million for Egypt, $25.8 million for Canada, $44.4 million for Cote d'Ivoire, $0.6 million for Equatorial Guinea and $4.6 million for the corporate offices, compared to $72.6 million for 2023. Capital expenditures in 2024 were attributable to expenditures primarily related to the new wells drilled as part of the drilling campaign in Canada, the workover and drilling program in Egypt and the expenditures associated with the preparation of the FPSO dry dock project in Cote d'Ivoire. Capital expenditures in 2023 were primarily related to the payments for the 2023 drilling campaigns in Egypt and Canada.

Recent Operational Updates

Gabon

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.

Egypt

The Company focused on enhancing production in 2024 through a series of planned workovers. The EA-55 well, drilled in October 2023, was completed and put online in January 2024. During the year, the planned workover program for 2024 was completed for 12 wells, including the K-81 well recompletion at the start of the first quarter of 2024, which was a carry-over from our 2023 drilling activity. The focus of the workover activities was to achieve peak production from the wells, significant improvements on the rate of production, and enhance production efficiency.

The Company deferred its 2024 drilling during the year to work up a robust drilling program. We have contracted a rig and commenced with the drilling of two wells December 2024. The first of the two wells was also successfully completed in December 2024, while the second well is expected to come on line in early 2025.

Cote d'Ivoire

As previously discussed, the FPSO will be placed in dry dock in early 2025 for planned maintenance and upgrades. It ceased hydrocarbon production as scheduled on January 31, 2025 and the final lifting of crude oil from the FPSO took place on February 5, 2025. The project team has commenced mobilization efforts, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO. The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departure from the field around March 2025. Significant development drilling is expected to begin in 2026 after the FPSO is expected to return to service with meaningful additions to production from the main Baobab field in CI-40, as well as a potential future development of the Kossipo field, which is also on the license.

Canada

We successfully drilled and completed four wells in 2024, all of which have been producing during the year. The wells were drilled with longer 2.75 mile laterals to improve the economics of the program. The new wells drilled resulted in a change in the production mix in Canada from about 60% liquids during the first quarter to about 75% after the wells came online with a lower gas-oil ratio. In early November 2024, a fifth well was drilled and we plan to put the well online in early 2025.

Commodity Price Hedging

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

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

Please see Part IV, Item 15., Note 10. Derivatives and Fair Value in our Consolidated Financial Statements for more information on the related hedges.

Cash on Hand

At December 31, 2024 and 2023, we had unrestricted cash of $82.6 million and $121.0 million, respectively, which as of certain dates, exceeded Federal Deposit Insurance Corporation insurance limits. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

Capital Resources, Liquidity and Cash Requirements

Our primary source of liquidity has been cash flows from operations and our primary use of cash has been to fund capital expenditures for development activities in the Etame Marin block. We continually monitor the availability of capital resources, including equity and debt financings that could be utilized to meet our future financial obligations, planned capital expenditure activities and liquidity requirements including those to fund opportunistic acquisitions. Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and our 2025 RBL Facility to support our current cash requirements during the next 12 months and beyond, including the FSO charter, drilling programs, as well as transaction expenses and capital and operational costs associated with our business segments' operations. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends for other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

Merged Concession Agreement

For information on the Merged Concession Agreement, see Part IV, Item 15., Note 12. Commitments and Contingencies to the Consolidated Financial Statements.

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RBL Facility Agreement and Available Credit

For information on our RBL Facility Agreement and Available Credit, see Part IV, Item 15., Note 13. Debt to the Consolidated Financial Statements. For information on our 2025 Facility Agreement and Available Credit, see Part IV, Item 15., Note 13. Debt and Note 20. Subsequent Events to the Consolidated Financial Statements.

Cash Requirements

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

Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In August 2023, a new abandonment study was completed and such study estimated abandonment costs of approximately $77.9 million ($45.9 million, net to VAALCO) on an undiscounted basis. The new abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC. In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement. The Company received payment of $15.6 million in March 2023. No additional activity was noted in the abandonment funding account during the remainder of 2023 and in 2024. At December 31, 2024, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. The Company is working with the Directorate of Hydrocarbons in Gabon to establish a payment schedule to resume funding of the abandonment fund. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.

Capital Projects - In December 2024, Vaalco secured a rig for the 2025/26 drilling campaign at Etame. Vaalco is currently finalizing locations and planning for the next drilling campaign, which is expected to commence in Q3 2025. We currently have a 10 to 15 well drilling campaign in Egypt, where we have completed the drilling of two wells. In Canada, we continue to drill, recomplete and workover wells adding to our production base and cash flows.

Leases - We are a party to several operating and financing lease arrangements, including operating leases, which may include corporate offices, drilling rigs, rental of marine vessels and helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, and equipment and vehicles used in operations. The annual costs of these leases are significant to us. For further information see Part IV, Item 15., Note 14. Leases to our Consolidated Financial Statements.

Merged Concession Agreement - On January 20, 2022, prior to the consummation of the TransGlobe Acquisition, TransGlobe announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics. In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signing bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession Agreement, we agreed to substitute the 2023, 2024 and 2025 payments and issue three $10.0 million credits against receivables owed from EGPC. We plan to make the final annual equalization payment of $10.0 million on or before February 1, 2026. We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the “Merged Concession Effective Date”). As of December 31, 2024, the $50.0 million of financial work commitments had been delivered to EGPC.

FSO Agreements – On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement (the “Bareboat Charter”) with World Carrier to replace the existing FPSO with an FSO unit at the Etame Marin block offshore Gabon. Pursuant to the Bareboat Charter, World Carrier will provide use of the Teli vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions. Pursuant to the Bareboat Charter, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO. As consideration for the performance by World Carrier of the Operator

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Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Bareboat Charter) until the end of the term, with such term being the same as the term in the Bareboat Charter. On October 19, 2022, we issued final acceptance certificate of the FSO. On December 4, 2022, the first lifting from the FSO was successfully completed at the same time the final remaining volumes from the FPSO were removed.

FPSO Maintenance – The FPSO will be in transit to dry dock in early 2025 for planned maintenance and upgrades. It ceased hydrocarbon production as scheduled on January 31, 2025 and the final lifting of crude oil from the FPSO concluded on February 6, 2025. The project team mobilization efforts are on schedule and have significantly progressed, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO. The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departure from the field around March 2025.

BWE Consortium – We are a member of the BWE Consortium with BW Energy and Panoro Energy, which was awarded the two blocks in the 12th Offshore Licensing Round in Gabon. The BWE Consortium and the Gabonese government came to an agreement on the commercial terms in February 2024. All parties to the BWE Consortium signed the PSC with the Gabonese Government during the fourth quarter of 2024. Pursuant to the terms of the PSC, BW Energy will be the operator with a 37.5% working interest, and VAALCO will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners. The two blocks, Niosi Marin Block (previously G12-13) and the Guduma Marin Block (previously H12-13), are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively. The two blocks, held by the BWE Consortium and the PSCs over the blocks, are currently under negotiation with the Gabonese government.

Dividend Policy – On February 14, 2023, we announced that our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 2023 and continued throughout 2024. Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.

Trends and Uncertainties

Geopolitical Conflict and Other Market Forces – Global conflicts, including Russia’s invasion of Ukraine, conflicts in the Middle East, and heightened tensions in the Pacific region, have significantly elevated global geopolitical tensions and security concerns. Economic sanctions, export controls, and other trade restrictions, for instance those that the U.S. Government and other nations implemented against Russia in light of its invasion of Ukraine or those relating to the conflict in the Middle East, could directly and indirectly continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets. The extended war between Russia and Ukraine and increasing hostilities in the Middle East, could continue to intensify and may cause prolonged uncertainty and volatility in commodity prices. The extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+.

ESG and Climate Change Effects – Sustainability matters continue to attract considerable public, regulatory and scientific attention. In particular, we expect continued required reporting attention on climate change issues and emissions of GHG, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion) and freshwater use.

For example, in March 2024, the SEC adopted final rules under SEC Release No. 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. These requirements are effective for the Company in various fiscal years, starting with its fiscal year beginning November 1, 2026. On April 4, 2024, the SEC determined to voluntarily stay the final rules pending certain legal

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challenges. The Company believes that the impact of these final rules on its consolidated financial statements and disclosures are not material. This increased attention to climate change and environmental conservation coupled with stepped up government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. 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. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG reporting requirements, including establishing and communicating short and long-term goals and targets, furthering the reduction of our carbon footprint and measurement of GHG emissions. Sustainability remains an important topic to us, and we are in the process of developing a multi-year plan to establish and document our progress in achieving goals we set for ourselves across all areas of sustainability. Our plans will enable us to monitor and improve matters related to ESG and climate change going forward.

For the past four years the Company has matured its reporting in line with the recommendations of the Task force on Climate-related Financial Disclosures (“TCFD”), which is recognized as the global standard in climate-related reporting. The full TCFD report was included within the 2023 Sustainability Report (rather than in this Annual Report on Form 10-K or in the annual report which was published in connection with the annual meeting), as the 2023 Sustainability Report details environmental, social and governance matters which the TCFD report forms an important part. The 2023 Sustainability Report is available on the Company's website, which is not incorporated by reference hereto.

Cash Flows

Our cash flows for the years ended December 31, 2024 and 2023 are as follows:

The $109.9 million decrease in net cash provided by operating activities during the year ended December 31, 2024 compared to the year ended December 31, 2023, was driven primarily by changes in operating assets and liabilities during the period. The net decrease in changes provided by operating assets and liabilities of $111.5 million for the year ended December 31, 2024 compared to the same period of 2023 was related to a decrease in cash provided by trade receivable, Accounts with joint venture owners, net and Egypt receivables and other, net (collectively $86.1 million). In addition, cash used by operating assets and liabilities increased due to a decrease in the accrued liabilities and other balances of $27.0 million. Partially offsetting these changes was an increase in cash provided on a decrease in cash used in Accounts Payable of $14.9 million.

The $4.9 million increase in net cash used in investing activities during the year ended December 31, 2024 was due to the increase in cash capital spending in 2024. In 2023 we incurred significant capital for the 2021/2022 Etame drilling campaign and the Etame field reconfiguration. In 2024 capital spending was primarily attributable to the costs associated with the recompletion and drilling program. In addition, VAALCO used $40.2 million in cash for the acquisition of

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Svenska which is offset by the cash received from Svenska in the amount of $41.0 million. See Part IV, Item 15., Note 4. Acquisitions to the Consolidated Financial Statements for further discussion of the acquisition.

Net cash used in financing activities during the year ended December 31, 2024 included $26.2 million for dividend distributions, $6.8 million for treasury stock repurchases made under our stock repurchase plan or as a result of tax withholding on options exercised and on vested restricted stock, and $10.5 million of principal payments on our finance leases partially offset by $0.4 million in proceeds from options exercised. For the twelve months ended December 31, 2023, cash used in financing activities included $26.8 million for dividend distributions, $23.6 million for treasury stock repurchased under our stock repurchase plan, and $7.2 million of principal payments on our finance leases partially offset by $0.7 million in proceeds from options exercised.

Regulatory and Joint Interest Audits

We are subject to periodic routine audits by various government agencies, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Part IV, Item 15., Note 12. Commitment and Contingencies to the Consolidated Financial Statements for further discussion.

CRITICAL ACCOUNTING ESTIMATES

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

Asset Retirement Obligations

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

We account for asset retirement obligations as required by ASC 410 — Asset Retirement and Environmental Obligations. Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made. If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in service date. In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated. We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability. We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

Income Taxes

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level

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of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. When it is estimated to be more-likely-than-not that all or some portion of the deferred tax assets will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered include earnings generated in previous periods, forecasted earnings, the expiration period of carryovers, and overall economic conditions of the industry. As of December 31, 2024, we had deferred tax assets of $266.5 million primarily attributable to Canada, Gabon and U.S. basis differences in fixed assets, foreign tax credit carryforwards, and foreign net operating loss carryforwards. A valuation allowance of $173.1 million has been established against the deferred tax assets as of December 31, 2024, as management has concluded that it was more-likely-than-not that only some portion of the deferred tax assets would be realized. In future periods, we may determine that it is more-likely-than-not that all or some portion of the deferred tax assets will be realized, and in such period all or a portion of this valuation allowance may be reversed as the evidence warrants.

In certain jurisdictions, we may deem the likelihood of realizing deferred tax assets as remote where we expect that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated financial position and results of operations. For further discussion, see Part IV, Item 15., Note 8. Income Taxes to the Consolidated Financial Statements.

Oil and Gas Accounting Reserves Determination

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

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

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

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

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

•assumed effects of regulation by governmental agencies; and

•future development and operating costs.

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

Management is responsible for estimating the quantities of proved crude oil, natural gas and NGLs reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the U.S. as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI for Gabon, Egypt and Cote d'Ivoire, while GLJ evaluates our Canadian reserves. Equatorial Guinea will receive a Management Case Report.

Our Board of Directors has established the Technical & Reserves Committee with the authority, responsibility and primary purpose of assisting the board of directors in its oversight responsibilities relating to evaluating and reporting on oil and gas reserves. The Technical & Reserves Committee, to the extent it deems necessary or appropriate, will oversee (i) annual review of oil and gas reserves, (ii) procedures for evaluating and reporting oil and gas producing activities, and (iii) compliance with applicable regulatory and securities laws relating to the preparation and disclosure of information with

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

Our senior executives and reserve engineers oversee the preparation of our crude oil, natural gas and NGLs reserves and related disclosures by our appointed independent reserve engineers. The Technical & Reserves Committee and senior management meet with the reserve engineers periodically to review the reserves process and results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between us and the independent reserve engineers.

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

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

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

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

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

Impairment of crude oil, natural gas and NGLs producing properties

We review the crude oil, natural gas and NGLs producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared reserve reports evaluated by independent reserve engineers adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results. For further discussion, see Part IV, Item 15., Note 9. Crude Oil, Natural Gas and NGLs Properties and Equipment, net to the Consolidated Financial Statements.

Impairment of Unproved Property

We evaluate our undeveloped crude oil, natural gas and NGLs leases for impairment on at least a quarterly basis by considering numerous factors that could include nearby drilling results, seismic interpretations, market values of similar assets, existing contracts and future plans for exploration or development. When undeveloped crude oil, natural gas and NGLs leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist mainly of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and to Block P in Equatorial Guinea. In connection with the TransGlobe Acquisition as discussed under Part IV, Item 15., Note 4. Acquisitions to the Consolidated Financial Statements, reserves in Egypt and Canada were also attributed to undeveloped properties and leasehold costs.

Business Combinations

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

In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil, natural gas and NGLs properties. If sufficient market data is not available regarding the fair values of proved and unproved

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properties, estimates of the fair value of crude oil and gas reserves are prepared. Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and capital costs are used to estimate future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based discount rate and risk adjustment factors determined appropriate at the time of the acquisition. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

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

ACCOUNTING STANDARDS

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