NYSE: EGY

•Continue planning for additional development of our properties;

•Preserve a strong balance sheet by maintaining conservative leverage ratios and exhibiting financial discipline;

•Opportunistically hedge against exposures to changes in crude oil, natural gas or NGLs prices; and

•Actively pursue strategic, value-accretive mergers and acquisitions of similar properties to diversify our portfolio of producing assets.

We believe that our quality portfolio, strong management and technical expertise specific to the markets in which we operate, and our ongoing focus on maintaining a competitive cost structure and disciplined capital allocation framework, position us to achieve our business strategy and navigate a variety of commodity price environments. Over the past years, we have delivered on our focused strategy and believe we will continue to do so with the organic growth programs across our diversified portfolio over the coming years.

Divestment of Non-Core Assets

On February 4, 2026, the Company entered into an asset purchase agreement (the “Canada APA”) to sell all the operating assets in Canada (the “Canada Asset Divestment”) to a third party purchaser for a purchase price of approximately $24.4 million (C$33.4 million), 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 (C$34.9 million), subject to additional customary post-closing adjustments. 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.

SEGMENT AND GEOGRAPHIC INFORMATION

For additional operating segment and geographic financial information, see Part IV, Item 15., Note 19. Segment Information to the Consolidated Financial Statements. Our reportable operating segments are Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea and, prior to the Canada Asset Divestment, Canada.

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The following table sets out a brief comparative summary of certain key data for each of the Company’s operating segments. Additional data and discussion are provided in Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report on Form 10-K.

Year Ended December 31, 2025As of December 31, 2025

Production Volumes(1)
Percentage of Total ProductionRevenueYear-End Estimated Proved ReservesPercentage of Total Estimated Proved Reserves

(In MBoe)(In thousands)(in MBoe)

Gabon2,535 42 %$181,738 10,001 23 %

Egypt2,730 45 %139,963 8,614 20 %

Cote d'Ivoire111 2 %18,397 18,210 43 %

Canada667 11 %19,174 6,158 14 %

Equatorial Guinea(2)
— — %— — — %

6,043 100 %$359,272 42,983 100 %

(1) Production volumes are reported on NRI basis.

(2) Undeveloped properties.

Gabon Segment

For the year ended December 31, 2025, our producing properties in Gabon produced approximately 2,535 MBoe or 42% of our total 2025 production. Our Gabon production for the period was 100% crude oil.

We own a 58.8% working interest in the Etame Marin block and we are the designated operator on behalf of the Etame Consortium. The Etame Marin block is located offshore Gabon in West Africa and covers an area of approximately 46,200 gross acres located 20 miles offshore in water depths of approximately 250 feet. The block is subject to a 7.5% back-in carried interest by the government of Gabon, which they have assigned to a third party. Our working interest will decrease to 57.2% beginning June 20, 2026 when the back-in carried interest increases to 10%.

The terms of the Etame PSC include provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price and a shared portion of Profit Oil determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. The term of the Etame PSC extends through 2028 with two five-year options to extend the PSC (the “PSC Extension”). The PSC Extension provides us with the extended time horizon necessary to pursue developing the resources we have identified at Etame. The government of Gabon has elected to take its Profit Oil in-kind in all years presented.

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 (the “BWE Consortium PSC”). The PSC covering the Niosi block has an initial exploration period of five years ending in 2029 with a work commitment to acquire new 3D seismic data and drill one well, while the PSC covering the Guduma block has an initial exploration period of three years ending in 2027 with a work commitment to carry out geological and geophysical studies. The Niosi and Guduma blocks cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively, and are adjacent to our Etame PSC. The Company holds a 37.5% non-operating working interest in these licenses.

Egypt Segment

For the year ended December 31, 2025, our Egypt Segment properties contributed approximately 2,730 MBoe or 45% of our total 2025 production. Our Egyptian production for the period was 100% crude oil.

In Egypt, our interests are spread across two regions: the Eastern Desert, which contains the Merged Concession, and the Western Desert, which contains the South Ghazalat concession. The Merged Concession is approximately 45,067 acres and the South Ghazalat concession is approximately 7,340 acres. Both of our Egyptian blocks are subject to PSCs with EGPC, the Egyptian government and VAALCO. We have an equal ownership interest, with EGPC owning the other portion, in the

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joint venture that has a 100% working interest in both PSCs. The PSC for the Merged Concession has a term ending in 2035. The term of the South Ghazalat PSC is scheduled to expire in 2039, subject to periodic evaluations and contingent upon continued successful drilling activities. Following the latest assessment and agreed-upon commitments, the South Ghazalat license is currently set to expire in 2027.

Cote d'Ivoire Segment

For the year ended December 31, 2025, the properties in Cote d'Ivoire produced approximately 111 MBoe or 2% of our total 2025 production. Our Cote d'Ivoire production for the period was 100% crude oil.

The Company holds a 27.4% non-operated working interest (30.4% paying interest) in CI-40 in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa. Crude oil from the Baobab field is produced to a dedicated FPSO with the associated natural gas delivered onshore via a subsea pipeline. The PSC license in Cote d’Ivoire has a term expiring in April 2038. The field has been developed with 24 subsea production wells and five water injector wells tied back to the FPSO. At year end, all production wells were shut in as the FPSO was off station in dry dock. Prior to shut in of the field, seven of these wells were in production, two were injecting and the other 20 were shut in. We also own a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.

In 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 in 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 following the FPSO’s return to service. The drilling campaign is anticipated 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. The block’s first exploration period ends in May 2026. Entering into the block’s second exploration period will require the commitment to reprocess seismic data and drill a well.

Canada Segment

For the year ended December 31, 2025, the properties in Canada produced approximately 667 MBoe or 11% of our total 2025 production. Our Canadian production for the period was 32% crude oil, 36% natural gas and 32% NGLs.

Prior to the Canada Asset Divestment, we owned production and working interests in Cardium light oil and Mannville liquids-rich gas assets in Harmattan, which is a core play in the Western Canadian Sedimentary Basis, and is located approximately 80 kilometers north of Calgary, Alberta. Prior to the Canada Asset Divestment, we also owned a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes was processed. All gas was delivered to a third party non-operated gas plant for processing.

Following the Canada Asset Divestment, the Company plans to wind down its subsidiary in Canada.

Equatorial Guinea Segment

We currently own a 60% working interest in an undeveloped portion of Block P offshore Equatorial Guinea where we are the designated operator. In the event that there is commercial production from Block P, the Company is obligated to make a one-time potential future payment of $6.8 million to the national oil company of Equatorial Guinea, who is a party to the Block P PSC. The Block P PSC provides for a development and production period of 25 years, commencing from the first oil production from Block P. We have completed a feasibility study of a standalone production development opportunity of the Venus field discovery on Block P and submitted a plan of development (“Venus Plan of Development”) to the Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”), which was approved in September 2022.

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After further negotiations and the agreement on certain terms relating to the joint operations were reached, the EG MMH directed that activities relating to the Venus Plan of Development resume in August 2023. These developments required a Third Amendment to the Joint Operating Agreement (“JOA”), which was approved by all parties to the JOA, and the EG MMH in February 2024. In late 2024, work commenced on the Front End Engineering and Design (“FEED”) to enable a Final Investment Decision (“FID”) on the Venus Plan of Development. In the second quarter of 2025, the Company completed the initial FEED study that confirmed the viability of the development concept and is currently evaluating alternative technical solutions which may deliver enhanced economic value. We currently 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.

Production Sharing Contracts

Exploration and production activities of our assets in Gabon, Egypt, Cote d'Ivoire, Nigeria and Equatorial Guinea are generally governed by PSCs.

Our oil entitlement under the PSCs is generally the sum of cost oil, profit oil and excess cost oil, if applicable. Under the terms of the PSCs, the Company is typically the contractor partner (“Contractor”) and bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred (“Cost Oil”) and a stipulated share of production after cost recovery (“Profit Oil”).

The Contractor may be obligated to make royalty payments to the host government of each country using a variable percentage based on gross daily production levels. The remaining oil production, after deducting the gross royalty, if any, is split between Cost Oil and Profit Oil. Cost Oil is up to a maximum percentage and is allocated to recover approved operating and capital costs spent on specific projects. Excess Cost Oil, which is Cost Oil less the actual cost recovery, is further shared between the host government and the Contractor. Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.

In Egypt, our share of royalties is paid out of the government's share of production, while in Gabon, the government receives a fixed royalty rate of 13%. Additionally, the income tax to which the Contractor is subject to (“Profit Oil Tax”), is deemed to have been paid to the host government as part of the payment of Profit Oil or is captured in the entitled share of Profit Oil production paid in-kind to the host government, and therefore no additional tax burden is due. Under this arrangement taxation is based on a set percentage of average daily production volume.

DRILLING ACTIVITY

The drilling campaign in Egypt, which started in late 2024 and continued into 2025, contributed to consistent production growth. In the fourth quarter of 2025, the Company commenced its Phase Three Drilling Program in Gabon with the drilling of one well in the Etame field. After completing our drillings at the Etame platform, we expect to move the drilling rig to the SEENT and Ebouri platforms where we have several wells and workovers planned to enhance production and potentially add reserves. Significant development drilling is also expected to begin in Cote d’Ivoire in the fourth quarter of 2026 after the FPSO returns to service following the completion of the rig refurbishment.

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The following table sets forth the number of net exploratory and development wells drilled in the last three years:

202520242023

ProductiveDryIn ProgressProductiveDryIn ProgressProductiveDryIn Progress

Gabon

Exploratory wells—————————

Development wells——1——————

Egypt

Exploratory wells11—————2—

Development wells16—12——16——

Cote d'Ivoire

Exploratory wells—————————

Development wells—————————

Canada

Exploratory wells—————————

Development wells———4—12——

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Operational Updates,” for additional description of Vaalco’s drilling and completion activities during the year ended December 31, 2025.

PRODUCTIVE WELLS

The following table sets forth information at December 31, 2025 relating to the productive wells in which we owned a working interest as of that date. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.

Productive crude oil wellsProductive natural gas wells

GrossNetGrossNet

Gabon148.2——

Egypt147147——

Cote d'Ivoire71.9——

Canada7068.35451.1

Total Productive crude oil wells238225.45451.1

ACREAGE

The following table sets forth information as of December 31, 2025 relating to our leasehold acreage.

DevelopedUndevelopedTotal

Acreage in thousandsGrossNetGrossNetGrossNet

Gabon6.94.11,250.4477.21,257.3481.3

Egypt29.229.223.323.352.552.5

Cote d'Ivoire3.51.0611.6409.2615.1410.2

Canada48.544.526.622.675.167.1

Equatorial Guinea——57.334.457.334.4

Total acreage88.178.81,969.2966.72,057.31,045.5

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Summary of Acreage Terms

The expiration dates of the term of our concessions associated with each operating area are as follows:

TermExtension Option

Gabon

Etame Marin2028Two 5-year options

Niosi Marin20293 years

Guduma Marin20273-year and 2-year options

Egypt

Merged Concession20355 years

Western Desert2027—

Cote d'Ivoire

Block CI-402038—

Block CI-705202630-month and 24-month options

Equatorial Guinea25 years from first oil production

For Canada, a significant portion of undeveloped acres is generally held by production by areas that are producing reserves. At December 31, 2025, approximately 67% of Canada’s net undeveloped acreage (15,102 acres) has no expiration risk within the next five years (2026 through 2030).

RESERVE INFORMATION

Estimated Reserves and Estimated Future Net Revenues

Reserve Data

The tables below set forth our estimated net proved reserve quantities for the year ended December 31, 2025. Our reserves information was evaluated by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Prior to 2025, reserves information for Canada was independently evaluated by GLJ Ltd. (“GLJ”). The proved reserve quantities are calculated based on our NRI.

Year Ended December 31, 2025

Crude Oil (MBbls)
Natural Gas (MMcf)(1)
NGLs (MBbls)
Total (MBoe)(1)

Proved developed reserves

Gabon5,287——5,287

Egypt8,177——8,177

Cote d'Ivoire————

Canada(2)
1,1799,0591,3294,018

Total proved developed reserves14,6439,0591,32917,482

Proved undeveloped reserves

Gabon4,714——4,714

Egypt437——437

Cote d'Ivoire17,0116,954—18,210

Canada(2)
1,1633,1504522,140

Total proved undeveloped reserves23,32510,10445225,501

Total proved reserves37,96819,1631,78142,983

(1)To convert Natural Gas to MBoe, MMcf is divided by 6 for Canada reserves, and MMcf is divided by 5.8 for Cote d'Ivoire reserves.

(2)Proved developed and proved undeveloped reserves in Canada attributed to assets held for sale as of December 31, 2025.

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In accordance with the current SEC guidelines, estimates of future net cash flows from our properties and the present value thereof are made using the average of the first-day-of-the-month price for each of the twelve months of the year adjusted for quality, transportation fees and market differentials. Such prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.

For 2025 and 2024, the adjusted average prices used for our reserves estimates were as follows:

Year Ended December 31,

20252024

Crude Oil ($/Bbl)

Gabon$66.60 $81.08

Egypt$57.66 $65.48

Cote d'Ivoire$68.95 $79.70

Canada$61.61 $69.12

Natural Gas ($/Mcf)

Cote d'Ivoire$2.77 $2.77

Canada$1.07 $0.95

Natural Gas Liquids ($/Bbl)

Canada

Ethane$2.90 $3.52

Propane $19.67 $19.46

Butane $25.88 $30.68

Condensates$62.44 $69.59

Standardized Measure

The following table sets forth the standardized measure of discounted future net cash flows:

As of December 31,

202520242023

(in thousands)

Gabon$31,561 $73,011 $107,824

Egypt118,052 135,139 161,747

Cote d'Ivoire232,625 124,143 —

Canada(1)
27,771 47,107 72,363

Standardized measure of discounted future net cash flows$410,009 $379,400 $341,934

(1) Discounted future net cash flows in Canada attributed to assets held for sale as of December 31, 2025.

The information set forth in the tables includes revisions for certain reserve estimates attributable to proved properties included in preceding years’ estimates. Such revisions are the result of additional information from subsequent completions and production history from the properties involved or the result of an increase or decrease in the projected economic life of such properties resulting from changes in product prices, estimated operating costs and other factors. Crude oil amounts shown for Gabon, Egypt and Cote d’Ivoire are recoverable under the respective PSCs, and the reserves in place at the end of the contract remain the property of each host government. The reserves at the end of the contract, including extensions, are not included in the table above.

We do not reflect proved reserves on discoveries in our reserve estimates until such time as a development plan has been prepared and approved by our joint venture owners and the host government, where applicable.

There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a

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subjective process of estimating underground accumulations of crude oil, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. The standardized measure of discounted future net cash flows should not be construed as the current market value of the estimated crude oil, natural gas and NGLs reserves attributable to our properties.

Proved Undeveloped Reserves

Historically, we have reviewed on an annual basis all of our proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists.

The following table discloses our estimated PUD reserve activities:

Proved Undeveloped Reserves

(MBoe)

Beginning proved undeveloped reserves at December 31, 202424,128

Undeveloped reserves converted to developed reserves(1,172)

Revisions1,326

Extensions and discoveries1,219

Ending proved undeveloped reserves at December 31, 202525,501

Our PUD reserves at December 31, 2025 increased by 1.4 MMBoe, primarily due to:

Conversion to Proved Developed — Conversions of 1.2 MMBoe are attributable to our Egypt segment where we had four wells, which were previously classified as PUDs, were drilled and converted to proved developed producing (“PDP”) as part of the 2025 drilling program. We also had one well in our Gabon segment, which was previously classified as PUD and was converted to PDP due to operational optimization where the reserves were confirmed to be accessible through existing infrastructure. The Company spent approximately $19.0 million in 2025 to convert PUDs to PDPs.

Revisions of Previous Estimates — We had total net positive revisions of 1.3 MMBoe in 2025. We had an increase of 1.9 MMBoe from our Cote d’Ivoire segment which includes increased recovery expectations from the upcoming Phase 5 drilling program supported by additional technical analysis. We also had an additional total upward revision of 0.4 MMBoe due to future well performance expectations in Egypt and updates to the gas supply in Gabon. These positive revisions were offset by negative revisions of 1.0 MMBoe in Canada due to wells that were not reasonably expected to be developed within the five-year timeframe in accordance with the SEC guidance.

Extensions and Discoveries — Extensions and discoveries of 1.2 MMBoe are associated with the drilling program in Gabon that extended the Etame Field and added new, proved undeveloped locations on the Company’s existing acreage in the Etame block.

As of December 31, 2025, we plan to drill all scheduled PUD locations within the next five years and within the five years following the initial disclosure of the PUDs as proved reserves. All PUDs are tracked with respect to the year the reserves were initially booked to verify compliance. The PUD schedule of the Company is reviewed and approved by management as part of our reserves control process and the schedule is also reviewed by our independent petroleum engineers.

Controls over Reserve Estimates

Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our crude oil, natural gas, and NGLs reserves quantities and present values in compliance with SEC regulations and generally accepted accounting principles in the U.S. (“GAAP”). Compliance with these rules and regulations with respect to our reserves is the responsibility of the Technical & Reserves Committee of the Board of Directors (the “Technical & Reserves Committee”) and our reservoir engineer, who is our principal engineer. Our principal engineer has over 25 years of experience in the crude oil and natural gas industry, including over five years as a reserve evaluator and trainer, and is a qualified reserves estimator, as defined by the Society of Petroleum Engineers’ standards. Further professional qualifications include degrees in geological engineering and petroleum engineering, with a Master’s

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degree in petroleum engineering, extensive internal and external reserve training, and asset evaluation and management. In addition, the principal engineer is an active participant in industry reserve seminars, professional industry groups and is a member of the Society of Petroleum Engineers. The Technical & Reserves Committee meets periodically with senior management to discuss matters and policies related to reserves.

Our reserves estimation process involves methods generally accepted in the industry to assess our proved reserves, including production decline curve analysis methods, and may include volumetric methods, material balance methods, and reservoir simulation methods, or a combination of these methods, as well as taking into account economic parameters and considerations in finalizing these assessments, as appropriate. Technical information used by us to assess our proved reserves estimates may include geological, geophysical, engineering and financial data as well as other relevant static and dynamic data. In order to satisfy the requirements for establishing a reasonable certainty for proved reserves, including material increase in proved reserves estimates, we adopt field-tested repeatable and consistent reliable technologies, which may include, among others, logging, 3D and 4D seismic data, rock core analyses, static or dynamic pressure tests and production well testing, as appropriate. Where appropriate analogous reservoirs are available, we will use analogous reservoir parameters to enhance the quality of our reserve assessment results so as to be consistent with the reliable results required for proved reserves assessment as specified in applicable SEC rules.

Our controls over reserve estimation include engaging and retaining qualified independent petroleum and geological firms with respect to reserves information. We provide information to our independent reserve engineers about our crude oil, natural gas and NGLs properties in Gabon, Egypt, Cote d'Ivoire and Canada which includes, but is not limited to, production profiles, ownership and production sharing rights, prices, costs and future drilling plans. Our independent reserve engineers prepare their own estimates of the reserves attributable to our properties. The reserves estimates for our Gabon, Egypt, Cote d'Ivoire and Canada assets shown herein have been independently evaluated by NSAI and our Technical & Reserves Committee. Reserves estimates for Canada assets prior to 2025 had been independently evaluated by GLJ.

NET VOLUMES SOLD, PRICES, AND PRODUCTION COSTS

Net volumes sold, average sales prices per unit, and production costs per unit for our 2025, 2024 and 2023 operations are shown in the tables below.

Production Volumes (2)

Sales Volumes (2)

Average Sales Price (2)

Average Production

Cost (2)

Crude Oil (MBbl)Natural Gas (MMcf)NGLs (MBbl)Crude Oil (MBbl)Natural Gas (MMcf)NGLs (MBbl)Crude Oil (Per Bbl)Natural Gas (per Mcf)NGLs (Per Bbl)Total

(per BoE)

Year Ended December 31, 2025

Gabon2,535——2,735——$65.76 $— $— $30.96

Egypt2,730——2,730——51.27 — — 19.61

Cote d'Ivoire 111——238——77.36 — — 41.80

Canada2141,4492122141,44921261.65 1.78 20.12 12.68

Total5,5901,4492125,9171,449212$56.11 $1.78 $20.12 $24.83

Year Ended December 31, 2024

Gabon2,783——2,584——$78.81 $— $— $24.08

Egypt2,585——2,585——56.47 — — 19.64

Cote d'Ivoire (1)
1,058——1,223——77.74 — — 31.08

Canada3501,5422693501,54226970.69 1.04 25.43 12.99

Total6,7761,5422696,7421,542269$65.64 $1.04 $25.43 $22.51

Year Ended December 31, 2023

Gabon3,197——3,196——$79.80 $— $— $27.26

Egypt2,771——2,771——58.11 — — 19.77

Canada3341,5282703341,52827071.88 1.93 26.58 11.02

Total6,3021,5282706,3011,528270$69.84 $1.93 $26.58 $22.16

(1)Reflects sales and production costs from April 30, 2024 through December 31, 2024 related to the Svenska Acquisition.

(2)The production volumes, average sales price, sales volumes and per Boe information are reported on NRI basis.

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AVAILABLE INFORMATION

VAALCO Energy, Inc. is a Delaware corporation, incorporated in 1985 and headquartered at 2500 CityWest Blvd., Suite 400, Houston, Texas 77042. Our telephone number is (713) 623-0801 and our website address is www.vaalco.com. We make available, free of charge on our website, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, at https://www.vaalco.com/investors/sec-filings as soon as reasonably practicable after such reports are electronically filed with or furnished to the SEC. These reports and other information are also available on the SEC's website at https://www.sec.gov. Information contained on our website and the SEC’s website is not incorporated by reference into this Annual Report. We have placed on our website copies of charters for our Audit Committee, Compensation Committee and Environmental, Social and Governance Committee as well as our Code of Business Conduct and Ethics (“Code of Ethics”), Corporate Governance Principles and Code of Ethics for the CEO and Senior Financial Officers. Stockholders may request a printed copy of these governance materials by writing to the Company Secretary, VAALCO Energy, Inc., 2500 CityWest Blvd., Suite 400, Houston, Texas 77042. We intend to disclose updates, waivers or amendments to our Code of Ethics and Code of Ethics for the CEO and Senior Financial Officers on our website within four business days following the date of such update, waiver or amendment.

CUSTOMERS

For the years ended December 31, 2025, 2024 and 2023, our revenue concentration by customer for each operating segment are shown on the table below.

Year Ended December 31,

2025
2024 (1)
2023

Gabon100%100%100%

Egypt100%100%
62% and 38%

Cote d'Ivoire 100%
87% and 13%
—%

Canada
51%, 20% and 15%

41%, 32% and 21%

52%, 37% and 7%

(1)For Cote d'Ivoire, reflects sales from April 30, 2024 through December 31, 2024 related to the Svenska Acquisition.

EMPLOYEES AND HUMAN CAPITAL RESOURCE MANAGEMENT

We operate on the fundamental philosophy that people are our most valuable asset as every person who works for us has the potential to impact our success. Identifying quality talent is at the core of everything we do and our success is dependent upon our ability to attract, develop and retain highly qualified employees. Our core values include honesty/integrity, treating people fairly, high performance, efficient and effective processes, open communication and being respected in our local communities. These values establish the foundation on which our culture is built and represent the key expectations we have of our employees. We believe our culture and commitment to our employees creates an environment that allows us to attract and retain our qualified talent, while simultaneously providing significant value to us and our stockholders by helping our employees attain their highest level of creativity and efficiency.

Demographics

As of December 31, 2025, we had 281 full-time employees, 159 of whom were located in Gabon, 44 in Egypt, 11 in Canada, 1 in Cote d’Ivoire, 1 in Equatorial Guinea, 61 in Houston and 4 corporate employees based in the United Kingdom. We also had 44 contractors in Gabon, 17 contractors in Egypt, 2 contractors in Equatorial Guinea, 2 contractors in Cote d’Ivoire, 5 contractors in the United Kingdom, 8 contractors in Canada and 24 contractors in Houston as of December 31, 2025. We are not subject to any collective bargaining agreements, although some of the national employees in Gabon are members of the National Organization of Petroleum Workers union. We believe relations with our employees are satisfactory.

Diversity and Inclusion

We value building diverse teams, embracing different perspectives and fostering an inclusive, empowering work environment for our employees. We have a long-standing commitment to equal employment opportunity as evidenced by our Equal Employment Opportunity policy. Approximately 19% of our management team are female employees, 96% of our Gabon workforce is Gabonese and 85% of our Egypt workforce is Egyptian.

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Compensation and Benefits

Critical to our success is identifying, recruiting, retaining, and incentivizing our existing and future employees. We strive to attract and retain the most talented employees in the industry by offering competitive compensation and benefits. Our pay-for-performance compensation philosophy is based on rewarding each employee’s individual contributions and striving to achieve equal pay for equal work regardless of gender, race or ethnicity. We use a combination of fixed and variable pay including base salary, bonus, and merit increases, which vary across the business. In addition, as part of our long-term incentive plan for executives and certain employees, we provide share-based compensation to foster our pay-for-performance culture and to attract, retain and motivate our key leaders.

As the success of our business is fundamentally connected to the well-being of our people, we offer benefits that support their physical, financial and emotional well-being. We provide our employees with access to flexible and convenient medical programs intended to meet their needs and the needs of their families. In addition to this medical coverage, we offer eligible employees dental and vision coverage, health savings and flexible spending accounts, paid time off, employee assistance programs, voluntary short-term and long-term disability insurance and term life insurance. Additionally, we offer a 401(k) Savings Plan and Deferred Compensation Plan to certain employees. Certain employees receive additional compensation for working in foreign jurisdictions.

Workplace environment is also crucial in attracting and retaining key talent. Most of our offices offer a certain level of flexibility (i.e. work from home days and/or flexible core hours) to help meet the needs of the multigenerational workforce and the needs of the business. Our benefits and compensation packages vary by location and are designed to meet or exceed local laws and to be competitive in the marketplace.

Commitment to Values and Ethics

Along with our core values, we act in accordance with our Code of Ethics, which sets forth expectations and guidance for employees to make appropriate decisions. Our Code of Ethics covers topics such as anti-corruption, discrimination, harassment, privacy, appropriate use of company assets, protecting confidential information, and reporting Code of Ethics violations. The Code of Ethics reflects our commitment to operating in a fair, honest, responsible and ethical manner and also provides direction for reporting complaints in the event of alleged violations of our policies (including through an anonymous hotline). Our executive officers and supervisors maintain “open door” policies and any form of retaliation is strictly prohibited.

Professional Development, Safety and Training

We believe that key factors in employee retention are professional development, safety and training. We have training programs across all levels to meet the needs of various roles, specialized skill sets and departments across the Company. We provide compliance education as well as general workplace safety training to our employees and offer Occupational Safety and Health Administration training to key employees. We are committed to the security and confidentiality of our employees’ personal information and employ software tools and periodic employee training programs to promote security and information protection at all levels. We utilize certain employee turnover rates and productivity metrics in assessing our employee programs to ensure that they are structured to instill high levels of in-house employee tenure, low levels of voluntary turnover and the optimization of productivity and performance across our entire workforce. Additionally, we have a performance evaluation program which adopts a modern approach to valuing and strengthening individual performance through on-going interactive progress assessments related to established goals and objectives.

Communication and Engagement

We strongly believe that our success depends on employees understanding how their work contributes to our overall strategy. To this end, we communicate with our workforce through a variety of channels and encourage open and direct communication, including: (i) quarterly company-wide CEO updates; (ii) regular company-wide calls with management and (iii) frequent corporate email communications.

COMPETITION

The crude oil, natural gas and NGLs industry is highly competitive. Competition is particularly intense from other independent operators and from major crude oil, natural gas and NGLs companies with respect to acquisitions and

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development of desirable crude oil, natural gas and NGLs properties and licenses, and contracting for drilling equipment. There is also competition for the hiring of experienced personnel. In addition, the drilling, producing, processing and marketing of crude oil, natural gas and NGLs is affected by a number of factors beyond our control, which may delay drilling, increase prices and have other adverse effects, which cannot be accurately predicted.

Our competition for acquisitions, exploration, development and production includes the major crude oil, natural gas and NGLs companies in addition to numerous independent crude oil companies, individual proprietors, investors and others. We also compete against companies developing alternatives to petroleum-based products, including those that are developing renewable fuels. Many of these competitors have financial and technical resources and staff that are substantially larger than ours. As a result, our competitors may be able to pay more for desirable crude oil, natural gas and NGLs assets, or to evaluate, bid for and purchase a greater number of properties and licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of lower commodity prices, unsuccessful wells, volatility in financial markets and generally adverse global and industry-wide economic conditions. These companies may also be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. Our ability to generate reserves in the future will depend on our ability to select and acquire suitable producing properties and/or develop prospects for future drilling and exploration.

INSURANCE

For protection against financial loss resulting from various operating hazards, we maintain insurance coverage, including insurance coverage for certain physical damage, blowout/control of a well, comprehensive general liability, worker’s compensation and employer’s liability. We maintain insurance at levels we believe to be customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of certain prohibited substances into the environment. Such insurance might not cover the complete claim amount and would not cover fines or penalties for a violation of environmental law. We are not fully insured against all risks associated with our business either because such insurance is unavailable or because premium costs are considered uneconomic. A material loss not fully covered by insurance could have an adverse effect on our financial position, results of operations or cash flows.

REGULATORY

General

Our operations and our ability to finance and fund our operations and growth are affected by political developments and laws and regulations in the areas in which we operate. In particular, crude oil, natural gas and NGLs production operations and economics are affected by:

•change in governments;

•civil unrest;

•price and currency controls;

•limitations on crude oil, natural gas and NGLs production;

•tax, environmental, safety and other laws relating to the petroleum industry;

•changes in laws relating to the petroleum industry;

•changes in administrative regulations and the interpretation and application of administrative rules and regulations; and

•changes in contract interpretation and policies of contract adherence.

In any country in which we may do business, the crude oil, natural gas and NGLs industry legislation and agency regulation are periodically changed, sometimes retroactively, for a variety of political, economic, environmental and other reasons, the impact of which could substantially increase our costs or affect our operations. Numerous governmental departments and agencies issue rules and regulations binding on the crude oil, natural gas and NGLs industry. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. The regulatory burden on the crude oil, natural gas and NGLs industry increases our cost of doing business and our potential for economic loss.

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Gabon

The 2019 Hydrocarbons Law in Gabon contains provisions applicable to both the upstream and downstream segments. However, despite the publication of the 2019 Hydrocarbons Law, there are various issues and matters yet to be fully enacted by implementing regulations. Under the transitory provision contained in the 2019 Hydrocarbons Law, existing PSCs and other petroleum contracts, permits and authorizations remain in full force and effect until their expiration. However, any renewal or extension of those instruments is subject to the provisions of the 2019 Hydrocarbons Law, and its implementing regulations.

The 2019 Hydrocarbons Law also provides for obligations for immediate application, irrespective of the date of signature of existing PSCs or petroleum contracts and/or granting of petroleum permits and authorizations. These include (i) the requirement for foreign producers and explorers applying for an exclusive development and production authorization to conduct their operations in Gabon through a company incorporated in Gabon rather than through branches of entities incorporated in other jurisdictions; and (ii) the obligation for all companies undertaking hydrocarbon activities to domicile their site rehabilitation funds with the Bank of Central African States, which is the Central African Economic and Monetary Community (“CEMAC”) or a Gabonese bank or financial institution subject to the Central African Banking Commission, which supervises banks and financial institutions licensed to operate in CEMAC countries, within one year after the entry into force of the 2019 Hydrocarbons Law.

PSCs entered into between independent contractors and the State of Gabon (“State”) since the implementation of the 2019 Hydrocarbons Law must include a clause providing that participation by the State cannot exceed a 10% participating interest in the operations, to be carried by the contractor.

Under the 2019 Hydrocarbons Law, the direct or indirect assignment of a Contractor’s rights or obligations to third parties (non affiliates) under the PSC is subject to approval of the Minister of Petroleum. The State and the national operator have preemption rights, which the State must exercise within 60 days and the national operator must exercise within 45 days if the State does not exercise its rights within the 60 days. The preemption right of the State and the national operator also applies in change of control situations. In February 2024, the State/national operator exercised its preemption right in a share transaction involving a number of PSCs and concessions already in effect prior to 2014.

The 2019 Hydrocarbons Law also entitles the national operator to acquire a maximum 15% stake at market value in all PSCs as of the date of signature. Further, it also provides that the State of Gabon may acquire an equity stake of up to 10%, at market value, in an operator applying for or already holding an exclusive development and production authorization.

Of critical note, the Government of Gabon announced in October 2025 its intention to replace the current 2019 Hydrocarbons Law with a new dual legal framework, comprising separate Oil and Gas Codes. This new legislation, expected to be implemented during the third quarter of 2026, aims to enhance transparency, improve fiscal terms, and provide greater legal clarity for investors in the Gabonese oil and gas sector. While existing contracts are generally expected to be honored under transitional provisions, any future renewals, extensions, or new agreements will be subject to the provisions of this forthcoming framework, which could introduce changes to current operating conditions, fiscal regimes, and regulatory requirement.

Egypt

Laws and Regulations

The Egyptian Ministry of Petroleum and Mineral Resources (“MOP”) is the ministerial governmental authority responsible for the regulation and development of the oil and gas industry in Egypt. Certain government entities have been set up to help the MOP achieve its objectives.

Under the Egyptian Constitution, all oil and gas resources are under the control of the State of Egypt. Accordingly, only the State can grant rights for exploration and exploitation of oil and gas resources for interested investors. The Egyptian Constitution provides that concessions for the exploitation of such resources shall be issued by virtue of a law for a period not exceeding 30 years.

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Concession Agreement

The mechanism for granting a contractor the right to carry out oil and gas exploration and development activities is the concession agreement. Concession agreements have the force and privileges of law in Egypt, meaning each agreement is an Egyptian Act of Parliament. The concession agreement overrides any contradictory Egyptian laws but not the Egyptian Constitution. In the absence of any legal rule under the relevant concession agreement, the exploration and exploitation operations will be subject to the rules of the Fuel Materials Law No. 66/1953, as amended, and its executive regulation issued by Minister of Industry Decree No. 758/1972, as amended (the “Fuel Materials Law”), and related ministerial decrees, where applicable.

Concession agreements usually follow a standard format which may be updated by the MOP and the relevant government entity from time to time, with slight variations. The commercial terms of concession agreements are open to negotiation, but each concession agreement will typically set out certain factors such as: (i) minimum work and financial commitments associated with each exploration and development program; (ii) any bonus payment(s) to be paid by the contractor to the relevant government agency upon triggering events (usually tied to certain production milestones); (iii) royalties payable to the government in cash or in kind; (iv) exploration and development periods and extensions of each; (v) rules concerning the contractor's recovery of its costs and expenses in association with exploration, development and related operations; (vi) production sharing valuations; (vii) priority right to the relevant government entity to offtake the production for domestic needs; (viii) relinquishment obligations and the associated triggering events; and (ix) requirements and procedures to convert an area to a development and to obtain a development lease, conclude sales and offtake agreement, and to dispose of the contractor’s share of production.

Cost Recovery and Production Allocation

The concession agreement will set out in detail the distribution of cost recovery for the contractor, including a dedicated annex outlining the accounting procedures for treatment of costs, expenses, and taxes under the concession agreement. Typically, the contractor bears all the risks until a commercial discovery is made, and, following which, the joint operating committee (“JOC”) is formed. The contractor will then be entitled to recover a certain percentage of its costs related to its previous and ongoing exploration and development activities in proportion to its working interest in the concession agreement. These costs may be recovered from the total petroleum production at a rate set out under the concession agreement on a quarterly basis. If the recoverable expenditures exceed the amount recoverable from petroleum production in any period, the unrecovered portion of the expenditures can usually be carried forward to subsequent periods. Full title to fixed and movable assets that are charged to cost recovery will usually pass from the contractor to the relevant government agency when its total costs have been recovered in accordance with the concession agreement, or at the time of relinquishment of the concession agreement with respect to all assets chargeable to the operations whether recovered or not, whichever occurs earlier.

Ownership of Assets

Under the model concession agreements, the movable and immovable assets (other than lands, which become the government entities' property as of the purchase thereof) are transferred automatically and gradually from the contractor to the government entity, as they become subject to cost recovery pursuant to the cost recovery provisions of the concession. The contractor (through the JOC) only has the right to use such assets for the purpose of petroleum operations under the concession agreement.

Termination and Revocation of Concession

The concession agreement is terminated by the lapse of its term, unless terminated prematurely. In addition, the government has the right to prematurely terminate the concession agreement in several instances set out in the concession. The government may, among other things, terminate the concession in the event of a misrepresentation by the contractor, an assignment of the contractor's rights without obtaining the required approvals, or the contractor being declared bankrupt, or committing any material breach under the concession or the Fuel Materials Law. If the government deems that one of these causes (other than force majeure events) exists, it will give the contractor 90 days’ written notice to remedy and remove the cause. If, at the end of the 90-day notice period, the cause has not been remedied and removed, the concession agreement may be terminated by a presidential decree.

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Cote d'Ivoire

The Petroleum Code of Cote d'Ivoire (the “Petroleum Code”) is the main legislation governing the country's oil and gas sector. Due to the general nature of the Petroleum Code, most of the specific provisions governing petroleum exploration and production are included in petroleum contracts (the “Petroleum Contracts”) which implement the principles of the Extractive Industries Transparency Initiative, a global framework for disclosure and multi-stakeholder oversight. The Uniform Acts adopted by the Organization for the Harmonisation of Business Law in Africa (the “OHADA”), of which Cote d'Ivoire is a member state, apply to companies carrying out oil and gas activities in Cote d'Ivoire, especially the OHADA Companies Act. Oil and gas activities are subject to exchange control regulations applicable within the West African Economic and Monetary Union, which is an organization of West African states established to promote economic integration among countries that share the CFA franc as a common currency, and the Economic Community of West African States, a regional group of West African nations created to promote economic integration across the region. The main regulatory oversight bodies in Cote d'Ivoire include, among others, the Ministry of Mines, Petroleum and Energy, the Direction Générale des Hydrocarbures, and Société Nationale d'Opérations Pétroliéres de la Cote d'Ivoire (PETROCI), the national oil company for oil and gas operations.

The Petroleum Code requires abandonment and rehabilitation obligations to be included in the Petroleum Contracts. In addition, the Petroleum Code provides for the obligation to include environmental provisions, in particular environmental management plans, in the Petroleum Contracts.

Canada

Pursuant to The Constitution Act, 1867 (Canada), the Canadian federal government has primary jurisdiction over interprovincial oil and gas pipelines, import and export trade in oil and gas, and offshore oil and gas exploration and production. Proposed interprovincial pipeline projects require a regulatory review by the Canada Energy Regulator under the Canadian Energy Regulator Act (Canada) to proceed. An impact assessment by the Impact Assessment Agency and a determination by the Cabinet that a pipeline project is in the public interest will also likely be required under the Impact Assessment Act (Canada)(“IAA”). On October 13, 2023, the Supreme Court of Canada found the “designated projects” component of the IAA to be largely unconstitutional, ruling that it exceeded federal legislative jurisdiction. In response, the federal government introduced and passed legislative amendments to the IAA, and one of such amendments came into force on June 20, 2024. The amended IAA aims to align the legislation with the Supreme Court’s decision by focusing on areas of clear federal jurisdiction for impact assessments.

The Alberta Energy Regulator (“AER”) is the primary regulator of resource development in Alberta. It derives its authority from the Responsible Energy Development Act (Alberta) and several related statutes. AER regulatory approval is required for all oil and natural gas projects or activities in Alberta.

In addition to conducting project approvals, the AER regulates the lifecycle of projects and performs ongoing monitoring of oil and gas projects to ensure compliance with standards and conditions set out in the licenses and approvals it issues and in the AER directives and regulations. The AER also oversees project closure obligations.

Canada also has extensive climate change regulations at both the federal and provincial level mandating greenhouse gas (“GHG”) emission reductions by oil and natural gas producers. The federal government enacted the Greenhouse Gas Pollution Pricing Act (Canada) (the “GGPPA”), which came into force on January 1, 2019. While the GGPPA previously included a fuel charge, Regulations Amending Schedule 2 to the GGPPA and the Fuel Charge Regulations (SOR/2025-107) effectively removed the fuel charge by setting applicable rates to zero, effective April 1, 2025. The federal government intends to permanently repeal the fuel charge framework under Part 1 of the GGPPA, refocusing federal carbon pollution pricing requirements on industrial emissions. One component of the GGPPA regime that remains is an emissions trading system for large industry (the Output-Based Pricing System). The GGPPA allows provinces to develop their own carbon pollution pricing systems that meet the minimum federal benchmark, failing which the federal carbon pollution pricing system applies.

Alberta’s Technology Innovation and Emissions Reduction Regulation (“TIER”) regulates emissions of heavy industry in line with federal standards. TIER was significantly amended on December 3, 2025, through Order in Council 369/2025. Key changes include the introduction of investment credits as a new compliance pathway, allowing facilities to meet up to 90% of their compliance obligation through direct investments in on-site emission reductions. The amendments also provide flexibility for smaller emitters to opt out of the TIER system for 2025. The TIER fund price was frozen at C$95/tonne in May 2025, and the regulation's automatic review and expiry dates have been extended to December 31, 2030, and December 31, 2035, respectively.

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The Government of Alberta also enacted the Methane Emission Reduction Regulation (Alberta), which, in line with AER Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting and AER Directive 017: Measurement Requirements for Oil and Gas Operations, sets vent gas limits for methane per month, monitored through representative measuring data. Furthermore, the federal government announced new enhanced oil and gas methane regulations on December 16, 2025, expected to take effect in January 2028, with a target to reduce methane emissions by at least 75% below 2012 levels by 2030.

In Canada, there is a general presumption against the retroactive application of legislation absent an express statutory statement to the contrary. Significant changes to oil and gas regulations impacting existing projects are also often implemented through a prospective phase-in approach.

Equatorial Guinea

All hydrocarbons existing in Equatorial Guinea’s onshore territory, as well as in its sovereign and jurisdictional waters, are Equatorial Guinea property and part of the public domain. The monetization of such hydrocarbons is to be pursued exclusively by Equatorial Guinea under its constitution, which reserves the exploitation of mineral and hydrocarbons resources exclusively to Equatorial Guinea and the public sector. However, the constitution also provides that Equatorial Guinea can delegate to, grant a concession to or associate itself with private parties for purposes of exploration and production activities in the manner and cases set forth by law.

All contracts signed with the State of Equatorial Guinea for the exploration and production of hydrocarbons have taken the form of PSCs. PSCs are subject to ratification by the President of the Republic of Equatorial Guinea and become effective only on the date the contractor is notified of presidential ratification. The powers to sign and amend PSCs and supervise their performance belong to the ministry responsible for petroleum operations (the “EG Petroleum Ministry”). In addition, the national oil company of Equatorial Guinea holds, manages and takes participations in petroleum activities on behalf of Equatorial Guinea.

The 2006 Hydrocarbons Law currently in effect in Equatorial Guinea (the “Hydrocarbons Law”) incorporates the regime applicable to the exploration, appraisal, development and production of hydrocarbons, as well as the rules on their transportation, distribution, storage, preservation, decommissioning, refining, marketing, sale and other disposal. The Hydrocarbons Law contains provisions on a number of aspects concerning exploration and production operations and contracts, such as national content obligations, unitization, transfers and abandonment. The EG MHMD, which is currently the appointed EG Petroleum Ministry, has been exercising the powers contained within the Hydrocarbons Law.

Equatorial Guinea enforces national content regulations, established under its Hydrocarbons Law, with the primary goal of maximizing local participation and economic benefits from its oil and gas sector. Furthermore, they aim to increase the domiciliation of materials, equipment, and services within the country, fostering technology transfer and curbing capital outflow. Specific obligations also include the registration of all sector companies with the Ministry and the construction of prestigious office buildings by contractors after a commercial discovery.

In a move to bolster investor confidence and increase foreign investment, the Government of Equatorial Guinea passed Decree No. 100/2024 in early 2025. This decree introduces key regulations for the enforcement of judicial rulings against oil companies operating within the country, aiming to ensure procedural consistency and fairness in the execution of judgments. It reflects the government's commitment to safeguarding national interests while maintaining an attractive and predictable environment for international investors.

ENVIRONMENTAL REGULATIONS

General

Our operations are subject to various federal, state, local and international laws and regulations, including laws and regulations in Gabon, Egypt, Cote d'Ivoire, Canada (prior to the Canada Asset Divestment), Nigeria and Equatorial Guinea, governing the discharge of materials into the environment or otherwise relating to environmental protection or pollution control. The cost of compliance could be significant. While we are currently complying in all material respects with all environmental laws and regulations, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or the issuance of injunctive relief (including orders to cease operations). Environmental laws and regulations are complex and have tended to become more stringent over time. We also are subject to various environmental permit requirements. Some environmental

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laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or joint and several liability, which could subject us to liability for conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts drilling or imposes environmental protection requirements that result in increased costs to the crude oil, natural gas and NGLs industry in general, our business and financial results could be adversely affected. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing laws, rules and regulations regulating the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict, however, what effect future environmental regulation or legislation, enforcement policies, or claims for damages to property, employees, other persons, the environment or natural resources could have on us.

In addition, a number of governmental bodies have adopted, have introduced or are contemplating regulatory changes in response to the potential impact of climate change. Legislation, increased regulation and litigation regarding climate change could impose significant costs on us, our joint venture owners, and our suppliers, including costs related to increased energy requirements, capital equipment, environmental monitoring and reporting, and other costs to comply with such regulations. For example, several nations, including Gabon, Egypt, Cote d'Ivoire, Canada and Equatorial Guinea, have signed and officially entered into an international climate change accord (the “Paris Agreement”). The Paris Agreement calls for signatory countries to set their own GHG emissions targets, make these emissions targets more stringent over time and be transparent about the GHG emissions reporting and the measures each country will use to achieve its GHG targets. A long-term goal of the Paris Agreement is to limit global temperature increase to well below two degrees Celsius from temperatures in the pre-industrial era. The Paris Agreement is effectively a successor agreement to the Kyoto Protocol treaty, an international treaty aimed at reducing emissions of GHG, to which various countries and regions are parties. On January 20, 2025, the US President signed an executive order to withdraw the United States from the Paris Agreement for the second time, with the withdrawal taking effect in January 2026. Such executive order could impact the SEC’s adopted new rules requiring public companies to disclose extensive climate-related information in their SEC filings, which the SEC voluntarily stayed followed a number of petitions for review filed against the SEC that were consolidated before the US Court of Appeals for the Eighth Circuit.

The State of Gabon and the Republic of Equatorial Guinea did not sign the Global Renewables and Energy Efficiency Pledge at COP28. However, a few oil companies operating in Gabon signed the Oil and Gas Decarbonization Charter at COP28.

The United States has previously announced a target for the US to achieve a 50-52% reduction from 2005 levels in economy-wide GHG emissions by 2030. Following the Paris Agreement and its ratification in Canada, the Government of Canada also pledged to cut its emissions by 40-45% from 2005 levels by 2030. In June 2021, the Canadian federal government passed the Canadian Net-Zero Emissions Accountability Act (Canada), which provides a legal foundation and framework for Canada to achieve net-zero GHG emissions by 2050. In November 2024, the Canadian government released draft regulations aimed at capping GHG emissions from the oil and gas sector. Of note, the proposed regulations set a cap on GHG emissions within the sector, equivalent to 35% below 2019 levels by 2030 and introduce a cap-and-trade system designed to recognize better-performing companies and incentivize higher polluters to invest in cleaner production processes

Given the political significance and uncertainty around the impact of climate change and how it should be dealt with, we cannot predict how legislation and regulation, including the Paris Agreement and any related GHG emissions targets, potential prices on carbon emissions, incentives to use renewable forms of energy or other requirements, will affect our financial condition and operating performance. Apart from any new legal developments, increased awareness and any adverse publicity in the global marketplace about potential impacts on climate change by us or other companies in our industry could harm our reputation, restrict our access to capital or impact the marketability of crude oil, natural gas and NGLs. In addition, the potential physical impacts of climate change on our operations are highly uncertain and would be particular to the geographic circumstances in areas in which we operate. These may include changes in rainfall amounts, storm patterns and storm intensities, water shortages, changing sea levels, and changing temperatures. These impacts may adversely impact the cost, production, and financial performance of our operations.

In part, because they are economically developing countries, it is unclear how quickly and to what extent Gabon, Equatorial Guinea or Egypt will increase their regulation of climate change issues in the future. As of the date of this Annual Report, Equatorial Guinea has not adopted any new environmental legislation. Gabon has adopted Ordinance No. 019/2021 of September 13, 2021 on Climate Change, which ratification law has been published in the Official Gazette, with the objective of complying with the Paris Agreement (the "Ordinance on Climate Change"). The Ordinance on

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Climate Change particularly aims to: (a) provide a framework for targets to be set for controlling and reducing emissions and for increasing GHG absorption in the national climate change strategy and the national plans for climate change adaptation and mitigation; (b) define and develop tools and mechanisms for climate change adaptation and mitigation; (c) provide a framework for, and implement, strategies for adaptation, monitoring mitigation and assessment, action plans, policies, programs and adaptation and mitigation measures; (d) provide a framework and take effective response for adaptation and mitigation measures to facilitate the setting of specific sustainable development, security and energy efficiency goals; (e) promote and manage sustainable development through climate change mitigation and adaptation activities; (f) establish climate change financing mechanisms; and (g) complement international instruments addressing climate change. It also sets forth climate adaptation and mitigation measures for carbon intensive operators (which include petroleum companies) such as (a) the establishment of a National Plan on the Reduction of Gas Flaring with a zero flaring objective; (b) the establishment of a GHG emissions database and quota system, (c) a carbon offset register, and (d) penalties and sanctions for not complying with such measures. Egypt ratified the United Nations Framework Convention on Climate Change (“UNFCCC”) in 1994, signed the Paris Agreement in 2016 and ratified it in 2017. Egypt is among the top affected countries by climate change. Egypt is already implementing plans pertaining to energy resources diversification and acceleration of decreased carbon emissions, in line with its “Sustainable Development Strategy: Egypt Vision 2030”, the “Integrated Sustainable Energy Strategy 2035” and its “National Climate Change Strategy 2050”. Egypt hosted the United Nations Climate Change Conference-COP27, during which the role of the oil and gas sector was the highlight of the “Decarbonization Day” thereof. Egypt submitted in June 2023 a revised Nationally Determined Contribution (“NDC”) to the United Nations Development Programme, focusing on Egypt’s commitment to reduce emissions by 65% in the oil and gas sector (1.7 Mt CO2e) by 2030, increasing renewable energy capacities and alternative energy (including natural gas) sources to generate 42% of electricity by 2035, and increased policy actions and measures across key sectors including the oil and gas sector. In December 2023, during COP28, Egypt formally launched the first African voluntary carbon marketplace.

In addition to the ratification of the Paris Agreement, Côte d'Ivoire has implemented various climate regulations and policies to address the challenges of climate change. A Central Directorate in charge of the Fight against Climate Change was established to coordinate climate action. In 2022, Côte d'Ivoire submitted its revised NDC for 2021-2030, committing to reduce GHG emissions by 30.41% by 2030. The National Development Plan 2021-2025 includes climate change as one of its six priority areas. Other key climate-related policies include the National Gender and Climate Change Strategy, and the National REDD+ Strategy which look to develop credible carbon credit programs. Additionally, Côte d'Ivoire has joined international climate initiatives such as the Clean Development Mechanism and the Climate and Clean Air Coalition.

The Carbon Border Adjustment Mechanism (“CBAM”) is the EU’s carbon pricing tool designed to reduce carbon emissions and prevent carbon leakage by imposing a carbon price on certain imported goods. It requires importers to report embedded emissions in their products and eventually purchase CBAM certificates. Currently it applies to imports of cement, iron and steel, aluminum, fertilizers, hydrogen, and electricity with the aim to create a level playing field between EU and non-EU producers while encouraging cleaner industrial production globally. CBAM is poised to significantly reshape the global oil and gas trade landscape. As the mechanism gradually expands to encompass the oil and gas sector by 2028, with full coverage expected by 2036, industry players are bracing for substantial shifts in market dynamics. Based on WoodMac Research, CBAM's implementation could potentially increase crude and refined product prices by up to $5 per barrel, translating to approximately 30 euro cents per liter at the pump for consumers. This price adjustment is likely to alter the competitive landscape, favoring low-emission intensity crudes and potentially reshaping trade flows as producers and refiners adapt their strategies to maximize value in a carbon-constrained market.

Moreover, Gabon has recently adopted Law no. 007/2023 of November 2, 2023 on the prevention and management of disasters, which requires companies conducting activities defined as dangerous or operating at facilities that are deemed to have an impact on the environment, to obtain, as relevant, authorizations, or establish operational plans. There are no further guidelines on whether and how it will apply to the petroleum industry.

Any significant increase in the regulation or enforcement of environmental issues in any of our operating areas could have a material effect on us. Economically developing countries, in certain instances, have patterned environmental laws after those in the U.S. However, the extent that any environmental laws are enforced in economically developing countries varies significantly.

With regards to our development operations offshore West Africa, we are a member of Oil Spill Response Limited (“OSRL”), a global emergency and crude oil spill-response organization headquartered in London. OSRL has aircraft and equipment available for dispersant application or equipment transport, including various boom systems that can be used for

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offshore and shoreline recovery operations. In addition, VAALCO has a Tier 1 spill kit in-country for immediate deployment if required. See “