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Item 1. Business

2025-03-17 compared with 2024-03-15 · 303 added, 359 removed, 257 unchanged (72% of the section changed)

As used in this Annual Report, the terms, “we,” “us,” “our,” the “Company” and “VAALCO” refer to VAALCO Energy, Inc.

and its consolidated subsidiaries, unless the context otherwise requires.

We are a Houston, Texas-based, African-focused independent energy company with strong production and reserve portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada, currently engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

We own a working interest in, and are the operator of, the Etame PSC related to the Etame Marin block located offshore Gabon in West Africa.

The Etame Marin block covers an area of approximately 46,200 gross acres located 20 miles offshore in water depths of approximately 250 feet.

Currently, our working interest in the Etame Marin block is 58.8%, and we are designated as the operator on behalf of the Etame Consortium.

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% in June 2026 when the back-in carried interest increases to 10%.

We are also a member of a consortium with BW Energy and Panoro Energy (the “BWE Consortium”).

The BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon.

Negotiations to finalize the commercial terms were held in 2023, however they were halted late in the year due to the presidential elections.

The negotiations were started again at the request of the Gabonese Government in early February 2024, where the consortium and the government came to an agreement on the fiscal terms on February 9, 2024.

The next step is concluding the terms of PSCs with the Gabonese government.

BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners.

The two blocks, G12-13 and 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.

As a result of the business combination transaction with TransGlobe Energy Corporation (“TransGlobe”) in 2022 (the “Arrangement”), we own a 100% working interest in PSCs covering two regions:

the Eastern Desert, which contains the West Gharib, West Bakr and North West Gharib merged concessions (45,067 acres) and the Western Desert which contains the South Ghazalat concession (7,340 acres).

We also acquired TransGlobe’s production and working interests in Cardium light oil and Mannville liquids-rich gas assets located in Harmattan, Canada (47,400 gross acers developed).

On February 29, 2024, VAALCO Energy (Holdings), LLC (“Buyer”), a Delaware limited liability company and wholly-owned subsidiary of us, and Petroswede AB, a company incorporated in Sweden (“Seller”), entered into a Share Purchase Agreement (the “Share Purchase Agreement”) pursuant to which the Buyer will purchase all of the issued shares in the capital of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”) for $66.5 million in cash (the “Purchase Price”), subject to adjustment as described in the Share Purchase Agreement.

Pursuant to the terms and subject to the conditions of the Share Purchase Agreement, upon closing of the Acquisition (the “Closing”), Buyer will acquire Svenska and, as a result, 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.

Buyer will also acquire 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.

The Purchase Price will be funded by a combination of a dividend of cash on Svenska’s balance sheet to the Seller immediately prior to the consummation of the Acquisition and a portion of VAALCO’s cash-on-hand.

VAALCO estimates that cash due from VAALCO at Closing will be in the range of approximately $30 to $40 million.

At December 31, 2023, net proved reserves related to Gabon were 9.1 MBoe, net proved reserves related to Egypt were 10.6 MBoe and net proved reserves related to Canada were 9.0 MBoe.

We also currently own an interest in an undeveloped block offshore Equatorial Guinea, West Africa.

We own crude oil, natural gas and NGLs producing properties and conduct operating activities in Egypt, Canada, and offshore Gabon, with a focus on maximizing the value of our current resources and expanding into new development opportunities across Africa.

Our financial results are heavily dependent upon the margins between prices received for our crude oil, natural gas and NGLs production and the costs to find and produce such crude oil, natural gas and NGLs.

We intend to increase stockholder value by accretively growing production and value through organic drilling in a capital efficient manner to unlock the inherent value of our assets and making disciplined strategic acquisitions that meet our strategic and financial objectives.

OVERVIEW AND STRATEGY

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 and Equatorial Guinea, as well as producing properties in Canada.

Our overall business strategy is to maximize the value of our current resources and expand into new development opportunities across our strategically complementary asset base.

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

Specifically, we seek to:

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• Maximize our cash flow and income generation;

Continue planning for additional development at Etame, Egypt, and Canada as well as future activity in Equatorial Guinea;

• Continue planning for additional development of our properties;

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

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

We believe that we have strong management and technical expertise specific to the markets in which we operate, and that our strengths include:

Our reputation as a safe and efficient operator in Africa and Canada;

Our history of establishing favorable operating relationships with host governments and local joint venture owners;

Our subsurface knowledge of key plays and risks in the broader regional framework of discoveries and fields;

Our operational capacity to take on new development projects;

Our familiarity with local practices and infrastructure;

Our market intelligence to provide early insight into available opportunities.

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.

2024 ACQUISITION

On April 30, 2024, we completed the acquisition of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden (“Svenska”), 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.

In March 2025, the Company farmed into the CI-705 block offshore Côte d’Ivoire.

The Company will become operator of the CI-705 block with a 70% working interest and a 100% paying interest though a commercial carry arrangement and is partnering with two other parties.

The CI-705 block is located in the Tano basin, west of the Company's CI-40 Block, where the Baobab and Kossipo oil fields are located.

The Company has made approximately $3.0 million in cash payments related to the acquisition.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic financial information, see Note 5 to the Consolidated Financial Statements.

Our reportable operating segments are Gabon, Egypt, Canada and Equatorial Guinea.

For additional operating segment and geographic financial information, see Part IV, Item 15., Note 5.

Segment Information to the Consolidated Financial Statements.

Our reportable operating segments are Gabon, Egypt, Cote d'Ivoire, Canada and Equatorial Guinea.

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, 2024 As of December 31, 2024

Production Volumes (1)

Percentage of Total Production Revenue Year-End Estimated Proved Reserves Percentage of Total Estimated Proved Reserves

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

Gabon 2,783 38 % $ 205,954 11,063 25 %

Egypt 2,585 35 % 145,966 9,448 21 %

Cote d'Ivoire (2)

1,058 15 % 95,082 16,381 36 %

Canada 870 12 % 31,986 8,126 18 %

Equatorial Guinea (3)

— — % — — — %

7,296 100 % $ 478,988 45,018 100 %

(1) Production volumes are reported on NRI basis.

(2) For the period from April 30, 2024, the close date of the Svenska Acquisition, through December 31, 2024.

(3) Undeveloped properties.

Gabon Segment

Offshore – Etame Marin Block

The Etame PSC related to the Etame Marin block is located offshore Gabon.

During 2024, our producing properties in Gabon produced approximately 2,783 MBoe or 38% of our total production.

Our Gabon production for the period was 100% crude oil.

We own a working interest in, and are the operator of, the Etame PSC related to the Etame Marin block located offshore Gabon in West Africa.

The Etame Marin block covers an area of approximately 46,200 gross acres located 20 miles offshore in water depths of approximately 250 feet.

Currently, our working interest in the Etame Marin block is 58.8%, and we are designated as the operator on behalf of the Etame Consortium.

Currently, we own a 58.8% working interest in the Etame Marin block, and we are designated as the operator on behalf of the Etame Consortium.

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.

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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 with Gabon related to the Etame Marin block located offshore Gabon extends through 2028 with two five-year options to extend the PSC (“PSC Extension”).

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.

Prior to February 1, 2018, the government of Gabon did not take any of its share of Profit Oil in-kind.

Beginning February 1, 2018, the government of Gabon elected to, and has continued to, take its Profit Oil in-kind.

As of December 31, 2023, our core areas in Gabon are illustrated below:

The government of Gabon has currently elected to take its Profit Oil in-kind.

We are a member of the BWE Consortium that was provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon.

The BWE Consortium and the government came to an agreement on the fiscal terms of the PSC on February 9, 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 and Panoro Energy will have 37.5% and 25% working interests, respectively, as non-operating joint owners.

The two blocks, covered by the PSC, Niosi Marin Block (previously G12-13) and the Guduma Marin Block (previously H12-13) cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively, are adjacent to our Etame PSC

as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon.

In February 2025, the decree by the Gabonese government approving the PSCs for the Niosi Marin Block and the Guduma Marin Block was published.

Egypt Segment

In Egypt, as of December 31, 2023, our interests are spread across two regions:

For the year ended December 31, 2024, our Egypt Segment properties contributed approximately 2,585 MBoe or 35% of our total 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 West Gharib, West Bakr and North West Gharib merged concessions, and the Western Desert, which contains the South Ghazalat concession.

The Eastern Desert merged concession is approximately 45,067 acres and the Western Desert, South Ghazalat concession, is approximately 7,340 acres.

Both of our Egyptian blocks are PSCs with the Egyptian General Petroleum Corporation (“EGPC”), the Egyptian government and VAALCO.

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 joint venture that has a 100% working interest in both PSCs.

Our oil entitlement is the sum of cost oil, profit oil and excess cost oil, if any.

The government takes their share of production based on the terms and conditions of the respective contracts.

Our share of royalties is paid out of the government's share of production.

Taxes are captured in the Egyptian government's net entitlement oil due and therefore there is no additional tax burden to us.

On January 20, 2022, prior to the consummation of the Arrangement, 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 signature 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 and 2024 payment and issue two $10.0 million credits against receivables owed from EGPC.

We will make two further annual modernization payments of $10.0 million each beginning February 1, 2025 until 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, 2023, the $50 million of financial work commitments had been delivered to EGPC.

As the Merger Concession Agreement is effective as of February 1, 2020, there will be an effective date adjustment owed to us for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date.

The cumulative amount of the effective date adjustment was estimated at $67.5 million.

However, the cumulative amount to be received as a result of the effective date adjustment is currently being finalized with EGPC and could result in a range of outcomes based on the final price per barrel negotiated.

At December 31, 2023, we had received $17.2 million of the receivable and the remaining $50.3 million is recorded on our consolidated balance sheet in Receivables-Other, net.

The Egyptian PSCs provide for the government to receive a percentage gross royalty on the gross production.

The remaining oil production, after deducting the gross royalty, if any, is split between cost sharing oil and production sharing oil.

Cost sharing oil is up to a maximum percentage as defined in the specific PSC.

Cost oil is assigned to recover approved operating and capital costs spent on the specific project.

Unutilized cost sharing oil or excess cost oil (maximum cost recovery less actual cost recovery) is shared between the government and the contractor as defined in the specific PSCs.

Each PSC is treated individually in respect of cost recovery and production sharing purposes.

The remaining production sharing oil (total production less cost oil) is shared between the government and the contractor as defined in the specific PSC.

The Egyptian PSCs do not contain minimum production or sales requirements, and there are no restrictions with respect to pricing of the contractor's sales volumes.

Except as otherwise disclosed, all crude oil sales are priced at current market rates at the time of sale.

The following illustrates our Merged Concession in the Eastern Desert:

The following illustrates our concession, South Ghazalat, in the Western Desert:

The PSC for the Merged Concession has a term ending year 2035, while for South Ghazalat, we have until the end of March 2025 to extend the term of PSC depending on successful drilling activity.

Under the terms of the Merged Concession Agreement, the Company is obligated to make modernization payments to the Minister of Petroleum and Mineral Resources and is also required to deliver minimum financial work commitments.

Please see Part IV, Item 15., Note 12.

Commitments and Contingencies , to the Consolidated Financial Statements for further discussion on the modernization payments.

Cote d'Ivoire Segment

For the period from April 30, 2024, the closing date of the Svenska Acquisition, through December 31, 2024, the properties in Cote d'Ivoire produced approximately 1,058 MBoe or 15% of our total 2024 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 an initial term expiring on April 11, 2028 with a ten-year extension option that, if exercised, would extend the term until April 2038.

The field has been developed with 24 subsea production wells and 5 water injector wells tied back to a leased FPSO.

At year end, 9 of these wells were in production with the other 20 being shut in.

The FPSO will be in transit to dry dock in early 2025 for planned maintenance and upgrades.

It has 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.

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.

Canada Segment

In Harmattan, Canada, we own production and working interests in Cardium light oil and Mannville liquids-rich gas assets.

Harmattan is located approximately 80 kilometers north of Calgary, Alberta.

This property produces oil and associated natural gas from the Cardium zone and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 1,200 to 2,600 meters.

During 2024, the properties in Canada produced approximately 870 MBoe or 12% of our total production.

Our Canadian production for the period was 40% crude oil, 29% natural gas and 31% NGLs.

We own 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.

These properties produce oil and associated natural gas from the Cardium zone and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 2,000 to 2,600 meters.

The Harmattan property covers 49,100 gross acres of developed land and 28,900 gross acres of undeveloped land.

We also own a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes are handled.

We also own a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes are processed.

All gas is delivered to a third party non-operated gas plant for processing.

Under the Modernized Royalty Framework (the “MRF”) in Alberta, producers initially pay a flat royalty of 5% on production revenue from each producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable drilling and completion cost allowance.

well equals the applicable drilling and completion cost allowance.

After payout, producers pay an increased royalty of up to 40% that will vary depending on the nature of the resource and market prices.

Once the rate of production from a well is too low to sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually reaching a floor of 5%.

The MRF applies to the hydrocarbons produced by wells spud or re-entered on or after January 1, 2017.

The Royalty Guarantee Act (Alberta) came into effect in July 2019, amending the Mines and Minerals Act (Alberta) and guaranteeing no major changes to the oil and gas royalty structure for a period of 10 years.

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner.

The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands.

On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights.

Below is an illustration of our Canadian assets:

Equatorial Guinea Segment

We acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012.

The Equatorial Guinea Ministry of Mines and Hydrocarbons (“EG MMH”) approved our appointment as the operator of Block P on November 12, 2019.

We acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing our working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million to Compania Nacional de Petroles de Guinea Equitoria, (“GEPetrol”) in the event that there is commercial production from Block P.

On August 27, 2020, the amendment to the production sharing contract to ratify our increased working interest and appointment as operator was approved by the EG MMH.

In April 2021, Crown Energy, who held a 5% working interest, elected to default on its obligations from Block P.

On April 12, 2021, the majority of non-defaulting parties assigned the defaulting party’s interest to the non defaulting parties.

As a result, our working interest increased to 45.9% with the approval of a fourth amendment to the production sharing contract by the EG MMH.

On July 15, 2022, VAALCO, on behalf of itself and Guinea Ecuatorial de Petroleós (“GEPetrol”), submitted to the EG MMH a plan of development for the Venus development in Block P.

On September 26, 2022, the EG MMH approved the submitted plan of development.

Final documents to effect the plan of development are subject to EG MMH approval.

The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan for the area associated with the Venus development.

The 2023 budget for the plan was delivered on October 12, 2022 to the MMH and was approved effective November 16, 2022.

In February of 2023, we acquired an additional 14.1% participating interest, increasing our participating interest in the Block to 60.0%.

In March 2023, Atlas voted to participate in the Venus Development.

Amendment 5 of the PSC was approved by all parties in March 2023 with this updated participating interest, and execution of the Venus development plan has been initiated.

This increase of 14.1% participating interest increases our future payment to GEPetrol to $6.80 million at first commercial production of the Block.

The Third Amendment to the Joint Operating Agreement (“JOA”) was approved by GEPetrol and Atlas on Feb 18, 2024 and was further approved by the MMH on Feb 27, 2024.

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 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.

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 before proceeding.

The Third Amendment to the Joint Operating Agreement (“JOA”) was approved by all parties to the JOA, and the EG MMH in February 2024.

With the approval of the JOA, the work could commence on the engineering for the Venus Development to enable a Final Investment Decision (“FID”) on the Venus Development.

As of December 31, 2023, our Block P license in Equatorial Guinea is illustrated below:

The 2024 amended budget was approved by all partners in May 2024, and then approval was requested from EG MMH.

At the end of the 30-day waiting period, the budget was deemed to be approved, and the corresponding Authorization for Expenditures was sent to all partners.

It was unanimously approved in June 2024, and the implementation of the FEED phase was initiated.

The project is on schedule and focuses on key areas of drilling evaluations, facilities design, market inquiries and metocean review.

The ultimate objective is to obtain an FID determination by the end of the second quarter of 2025.

Production Sharing Contracts

Exploration and production activities of our assets in Gabon, Egypt, Cote d'Ivoire, 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

In Gabon, we commenced the 2021/2022 drilling campaign in December 2021.

The following table sets forth the total number of completed exploratory and development wells in 2024, 2023 and 2022 on a gross and net basis:

Exploratory wells

Development wells

In December 2021, we began drilling the ETAME 8H-ST development well that was completed in February 2022.

In 2022, we completed the Etame 8H-ST, North Tchibala 2H-ST, South Tchibala-1HB-ST2 and Avouma 3H-ST development wells.

The following table sets forth the total number of exploratory and development wells from the TransGlobe acquisition date in 2022 and 2023 in Egypt on a gross and net basis:

Exploratory wells

Development wells

The 18 wells drilled in 2023 along with the spud date for each were the EastArta-53 - January 15, 2023, the K-81 - February 2, 2023, the K-79 - February 21, 2023, the Arta-80 - March 10, 2023, the Arta-81 - March 21, 2023, the HE-5 Injector - April 16, 2023, the HE-3 - May 10, 2023, the Arta-82 - May 25, 2023, the Arta-84 - June 6, 2023, the NEG-5C1 - June 16, 2023, the K-80 - June 30, 2023, the K-84 - July 16, 2023, the K-85 - July 31, 2023, the M-24 - August 14, 2023, the Arta-91 - September 1, 2023, the EA-54 - September 12, 2023 and the EA-55 - October 4, 2023.

The two dry hole wells were the NWG-SC1 and the EA-54 which were abandoned during 2023.

The wells drilled in 2022 included the M-17 Development well which was spud on September 28, 2022 and rig released on October 17, 2022, the NWG-2INJ-1A planned as injector well but encountered oil and came online December 23, 2022 and the Arta-77Hz well in progress which came online in the first quarter of 2023.

The following table sets forth the total number of exploratory and development wells from the TransGlobe acquisition date in 2022 and all of 2023 in Canada on a gross and net basis:

2024 2023 2022 2024 2023 2022

Exploratory wells

Productive — — — — — —

Dry — 2 2 — 2 2

In progress — — — — — —

Development wells

The two wells drilled in 2023 were the 12-12-030-04W5/0 and the 16-30-029-03W5/0 with a spud date of January 28, 2023 and February 22, 2023, respectively.

The three wells drilled in 2022 were the 4-10-29-3W5, the 4-18-29-3W5 and the 4-24-29-4W5 well with a spud date of July 4, 2022, June 11, 2022 and June 23, 2022, respectively.

Productive 6 18 9 6 18 7.4

Dry — — — — — —

In progress 1 — 1 1 — 1

Total wells 7 20 12 7 20 10.4

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, 2024.

ACREAGE AND PRODUCTIVE WELLS

Below is the total acreage under lease or covered by the Etame PSC, Egypt PSCs, Canada PSCs and Block P and the total number of productive crude oil, natural gas and NGLs wells as of December 31, 2023:

Undeveloped(2)

Acreage in thousands

The following table sets forth information as of December 31, 2024 relating to our leasehold acreage.

Developed Undeveloped Total

Acreage in thousands Gross Net Gross Net Gross Net

Gabon 6.9 4.1 39.4 23.1 46.3 27.2

Egypt 29.2 29.2 23.3 23.3 52.5 52.5

Cote d'Ivoire 3.5 1.0 43.3 11.4 46.8 12.4

Canada 49.1 44.6 28.9 24.9 78 69.5

Equatorial Guinea — — 57.3 34.4 57.3 34.4

Total acreage 88.7 78.9 192.2 117.1 280.9 196.0

Productive crude oil wells

Summary of Acreage Terms

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

Term Extension Option

Gabon 2028 Two 5-Year Options

Merged Concession 2035 5 years

Western Desert (1)

Cote d'Ivoire 2028 10 years

Equatorial Guinea 25 years from first oil production

(1) We are currently in negotiations with EGPC to extend the term of the Western Desert concession as we continue to evaluate our strategic options in the area.

For Canada, a significant portion of undeveloped acres is generally held by production by areas that are producing reserves.

At December 31, 2024, approximately 59% of Canada’s net undeveloped acreage (14,584 acres) has no expiration risk within the next three years (2025 through 2027).

The following table sets forth information at December 31, 2024 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 wells Productive natural gas wells

Gross Net Gross Net

Gabon 14 8.2 — —

Egypt 130 130 — —

Cote d'Ivoire 7 1.9 — —

Canada 70 68.3 54 51.1

Total Productive crude oil wells 221 208.4 54 51.1

Productive natural gas wells

Total productive natural gas wells

(1) Excludes three wells shut-in due to the presence of high levels of H 2 S.

(2) The expiration dates for undeveloped acreage associated with each region is as follows:

For Gabon the undeveloped acres expire at the end of the license contract;

currently 2028 with two five-year options to extend the license contract.

For Egypt the undeveloped acres expire at the end of the license contracts;

currently 2035 with one five-year option to extend the license contract for the West Gharib, West Bakr and North West Gharib areas and 2039 with one 5 year extension for South Ghazlat area.

For Canada the undeveloped acres are generally held by production by areas that are producing reserves.

At December 31, 2023 approximately 82% of Canada’s net undeveloped acreage has no expiration risk.

Approximately 4.3 acres have risk of expiration from 2024 through 2027.

RESERVE INFORMATION

Estimated Reserves and Estimated Future Net Revenues

In accordance with the current SEC guidelines, estimates of future net cash flow 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 2023, the average of such prices used for our reserve estimate was $83.22 per Bbl for crude oil for Gabon.

Prices were $64.59 per Bbl for crude oil from Egypt and $71.67 per Bbl for crude oil from Canada.

For 2022, the average of such prices used for our reserve estimates was $100.35 per Bbl for crude oil from Gabon.

Prices were between $84.76 and $85.65 per Bbl for crude oil from Egypt and $89.61 per Bbl for crude oil from Canada.

For Gabon, this compares to the average of such price used for 2021 of $69.10 per Bbl.

For 2023, the adjusted average price for our reserves associated with natural gas was $1.91 per MCF, $5.20 per Bbl for Ethane, $20.18 per Bbl for propane, $36.69 per Bbl for butane and $74.76 per Bbl for condensates.

For 2022, the adjusted average price for our reserves associated with natural gas was $4.13 per MCF, $12.77 per Bbl for Ethane, $40.27 per Bbl for propane, $43.85 per Bbl for butane and $91.57 per Bbl for condensates.

Reserves reported below consist of net proved reserves related to the Etame Marin block located offshore Gabon in West Africa, the eastern desert and western area of Egypt and Harmattan area of west central Alberta, Canada.

The tables below sets forth our estimated net proved reserve quantities for the years ended December 31, 2023, 2022 and 2021.

The Gabon and Egypt information was prepared by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc.

Canada information was prepared by the independent firm, GLJ Ltd.

The 2021 information includes the Sasol interest in the Etame Marin block as we acquired Sasol’s interest on February 25, 2021.

As of December 31, 2023

Crude Oil (MBbls)

Natural Gas (MMcf)

Total (MBoe)(1)

The tables below sets forth our estimated net proved reserve quantities for the year ended December 31, 2024.

The Gabon, Egypt and Cote d'Ivoire information was evaluated by the independent petroleum engineering firm, Netherland, Sewell & Associates, Inc.

Canada information was evaluated by the independent firm, GLJ Ltd.

The proved reserve quantities are calculated based on our NRI.

Year Ended December 31, 2024

Crude Oil (MBbls) Natural Gas (MMcf) (1)

NGLs (MBbls) Total (MBoe) (1)

Proved developed reserves

Gabon 6,830 — — 6,830

Egypt 8,962 — — 8,962

Cote d'Ivoire 118 47 — 126

Canada 1,480 10,490 1,744 4,972

Total proved developed reserves 17,390 10,537 1,744 20,890

Proved undeveloped reserves

Gabon 4,233 — — 4,233

Egypt 486 — — 486

Cote d'Ivoire 15,134 6,504 — 16,255

Canada 1,286 5,590 936 3,154

Total proved undeveloped reserves 21,139 12,094 936 24,128

Total proved reserves 38,529 22,631 2,680 45,018

(1) To convert Natural Gas to MBoe, MMcf is divided by 6.

Standardized Measure and Changes in Proved Reserves

The following table shows changes in total proved Gabon reserves for all presented years:

Proved Reserves

As of December 31,

Proved reserves, beginning of year

Revisions of previous estimates

Extensions and discoveries

Purchase of reserves

Proved reserves, end of year

In February 2021, we completed the acquisition of Sasol’s interest in the Etame Marin block.

The reserves associated with the acquisition is included in the purchase of reserves category of the December 2021 balance.

In 2022, we drilled four wells that were previously included in the proved undeveloped category of the 2021 reserves.

In comparing the net proved reserves of 9.1 MMBoes at December 31, 2023 to the 10.2 MMBoes at December 31, 2022, we added 2.0 MMBoes of reserves through positive revisions of previous estimates.

2.8 MMBoes of the positive revisions were due to performance offset by 0.8 MMBoes of negative revisions through price.

The decrease of 17% in the average of the first-day-of-the-month prices for each of the years, adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was $83.22 for 2023 down from $100.35 for 2022.

The following table shows changes in total proved Egypt reserves for the year ended December 31, 2023 and the period October 14, 2022 through December 31, 2022:

Proved Reserves

As of December 31,

Proved reserves, beginning of year

Revisions of previous estimates

Extensions and discoveries

Purchase of reserves

Proved reserves, end of year

In 2023, eighteen wells were drilled in Egypt as part of the 2023 drilling campaign.

Two of these wells were exploratory that resulted in dry hole wells.

In comparing the net proved reserves of 10.6 MMBoes at December 31, 2023 to the 8.6 MMBoes at December 31, 2022, we added 4.7 MMBoes of reserves through positive revisions of previous estimates.

5.3 MMBoes of the positive revisions were due to performance offset by 0.6 MMBoes of negative revisions through price.

The decrease of 20% in the average of the first-day-of-the-month prices for each of the years, adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was $64.59 for 2023 down from $85.02 for 2022.

The following table shows changes in total proved Canada reserves for the year ended December 31, 2023 and the period October 14, 2022 through December 31, 2022:

Proved Reserves

As of December 31,

Proved reserves, beginning of year

Revisions of previous estimates

Extensions and discoveries

Purchase of reserves

Proved reserves, end of year

In comparing the net proved reserves of 9.0 MMBoes at December 31, 2023 to the 9.2 MMBoes at December 31, 2022, 1.2 MMBoes of reserves were removed through negative revisions of previous estimates.

0.9 MMBoes of the negative revisions were due to performance and 0.3 MMBoes of negative revisions were through price.

The decrease of 28% in the average of the first-day-of-the-month prices for the composite MBoe equivalent each of the years, adjusted for quality, transportation fees and market differentials required by SEC rules to determine reserves, was $39.63 per Boe for 2023 down from $55.30 per Boe for 2022..

(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.

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 2024 and 2023, the adjusted average prices of crude oil used for our reserves estimates were as follows:

Year Ended December 31,

Crude Oil ($/Bbl)

Gabon $ 81.08 $ 83.22

Egypt $ 65.48 $ 64.59

Cote d'Ivoire $ 79.70 $ —

Canada $ 69.12 $ 71.67

For 2024 and 2023, the adjusted average prices for our reserves associated with natural gas and NGLs were as follows:

Year Ended December 31,

Cote d'Ivoire

Natural Gas ($/Mcf) $ 2.77 $ —

Natural Gas ($/Mcf) $ 0.95 $ 1.91

Ethane ($/Bbl) $ 3.52 $ 5.20

Propane ($/Bbl) $ 19.46 $ 20.18

Butane ($/Bbl) $ 30.68 $ 36.69

Condensates ($/Bbl) $ 69.59 $ 74.76

Standardized Measure

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

As of December 31,

2024 2023 2022

(in thousands)

Gabon $ 73,011 $ 107,824 $ 244,427

Egypt 135,139 161,747 226,888

Cote d'Ivoire 124,143 — —

Canada 47,107 72,363 153,150

Standardized measure of discounted future net cash flows $ 379,400 $ 341,934 $ 624,465

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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 are recoverable under the Etame PSC, and the reserves in place at the end of the contract remain the property of the Gabon government.

Crude oil amounts shown for Egypt are recoverable under the Merged Concession and the western desert South Ghazalat concession, and the reserves in place at the end of those concessions remain the property of the Egyptian government.

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 government, where applicable.

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 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.

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.

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Historically, we have reviewed on an annual basis all of our PUDs to ensure an appropriate plan for development exists.

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities:

The following table discloses our estimated PUD reserve activities:

Proved Undeveloped Reserves

Future Development Costs

(in thousands

Beginning proved undeveloped reserves at December 31, 2023 6,193

Undeveloped reserves converted to developed reserves (56)

Acquisitions 15,670

Revisions 2,698

Extensions and discoveries (377)

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Our PUD reserves at December 31, 2024 increased by 17.9 MMBoe, primarily due to:

Acquisition — Acquisition of reserves of 15.7 MMBoe from the Svenska Acquisition.

Conversion to Proved Developed — Conversions of 0.1 MMBoe are attributable to our Egypt segment where one well was drilled, which was previously classified as PUDs was converted to proved developed producing (“PDP”) as part of the 2024 drilling program.

The Company spent approximately $11.4 million in 2024 to convert PUDs to PDPs in Egypt.

Revisions of Previous Estimates — We had positive revisions of 3.9 MMBoe primarily attributable to our Gabon segment due to increased recovery both from field performance and development activities, offset by negative revisions of 1.2 MMBoe in Canada.

Extensions and Discoveries — Extensions and discoveries of 0.4 MMBoe are primarily due to our Canada segment where the wells drilled in 2024 proved up areas surrounding the drilling locations and future drilling locations were added in that area.

Revisions of Previous Estimates — Revision of 0.9 MMBoe are primarily due to our Gabon segment where a well future well locations was added.

Conversion to Proved Developed — Conversions of 0.6 MMBoe are attributable to our Egypt segment where five wells that were previously classified ad PUDs were converted to PDP as part of the 2023 drilling program.

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.

Compliance with these rules and regulations with respect to our reserves is the responsibility of our Technical Reserve Committee and our reservoir engineer, who is our principal engineer.

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 30 years of experience in the crude oil and natural gas industry, including over 10 years as a reserve evaluator and trainer, and is a qualified reserves estimator, as defined by the Society of Petroleum Engineers’ standards.

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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 Reserve Committee of the Board of Directors meets periodically with management to discuss matters and policies related to reserves.

The Technical & Reserves Committee meets periodically with senior management to discuss matters and policies related to reserves.

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 and Canada which includes, but is not limited to, production profiles, ownership and production sharing rights, prices, costs and future drilling plans.

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 and Canada assets shown herein have been independently evaluated by NSAI (Gabon and Egypt), GLJ (Canada) and our Technical Reserve Committee.

The reserves estimates for our

Gabon, Egypt, Cote d'Ivoire and Canada assets shown herein have been independently evaluated by NSAI (Gabon, Egypt and Cote d'Ivoire), GLJ (Canada) and our Technical & Reserves Committee.

NET VOLUMES SOLD, PRICES, AND PRODUCTION COSTS

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Average Sales Price (3)

Average Production Cost (2)

Crude Oil (MBbl)

Natural Gas (MMcf)

Crude Oil (MBbl)

Natural Gas (MMcf)

Crude Oil (Per Bbl)

Natural Gas (per Mcf)

NGLs (Per Bbl)

Total (per BoE)

Average Production

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

Year Ended December 31, 2024

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

Egypt 2,585 — — 2,585 — — 56.47 — — 19.64

Cote d'Ivoire (1)

1,058 — — 1,223 — — 77.74 — — 31.08

Canada 350 1,542 269 350 1,542 269 70.69 1.04 25.43 12.99

Total 6,776 1,542 269 6,742 1,542 269 $ 65.64 $ 1.04 $ 25.43 $ 22.51

Year Ended December 31, 2023

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

Egypt 2,771 — — 2,771 — — 58.11 — — 19.77

Canada 334 1,528 270 334 1,528 270 71.88 1.93 26.58 11.02

Total 6,302 1,528 270 6,301 1,528 270 $ 69.84 $ 1.93 $ 26.58 $ 22.16

Year Ended December 31, 2022

(1) Reflects sales and production costs after the acquisition date, October 13, 2022

(2) The sales volumes and per Boe information are reported on NRI basis

(3) All of the Company’s production volumes in Gabon are from the Etame Marin block, all of the Company’s production volumes in Egypt are from the Petrobakr concession and substantially all of the Company’s production volumes in Canada are from the Harmattan area.

Gabon 2,971 — — 2,919 — — $ 103.09 $ — $ — $ 33.18

547 — — 547 — — 69.00 — — 21.84

72 396 73 93 335 63 79.56 4.00 36.12 9.33

Total 3,590 396 73 3,559 335 63 $ 97.24 $ 4.00 $ 36.12 $ 30.12

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

(2) Reflects sales and production costs from October 14, 2022 through December 31, 2022 related to the TransGlobe Acquisition.

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

AVAILABLE INFORMATION

VAALCO Energy, Inc.

is a Delaware corporation, incorporated in 1985 and headquartered at 9800 Richmond Avenue, Suite 700, Houston, Texas 77042.

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.

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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., 9800 Richmond Avenue, Suite 700, Houston, Texas 77042.

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 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 or amendment.

For the years ended December 31, 2023, 2022 and 2021, we sold our crude oil production from Gabon under a term contract with pricing in the month of lifting, adjusted for location and market factors.

For the period of August 2022 through December 2022, revenues in Gabon were concentrated in one customer that constituted 100% of revenues in Gabon.

For the year ended December 31, 2023, revenues in Gabon were concentrated in one customer that constituted 100% of revenues in Gabon.

For the period of October 14, 2022 through December 31, 2022, revenues in Egypt were concentrated with one customer that constituted 100% of revenues in Egypt.

For the year ended December 31, 2023, revenues in Egypt were concentrated in two separate customers that constituted approximately 62% and 38% of revenues in Egypt.

For the period of October 14, 2022 through December 31, 2022, revenues in Canada were concentrated in three separate customers that constituted approximately 54%, 32% and 14% of revenues in Canada.

For the year ended December 31, 2023, revenues in Canada were concentrated in three separate customers that constituted approximately 52%, 37% and 7% of revenues in Canada

For the years ended December 31, 2024, 2023 and 2022, our revenue concentration by customer for each operating segment are shown on the table below.

Year Ended December 31,

2023 2022 (2)

Gabon 100% 100% 100%

Egypt 100% 62% and 38% 100%

Cote d'Ivoire 87% and 13% — —

Canada 41%, 32% and 21% 52%, 37% and 7% 54%, 32% and 14%

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

(2) For Egypt and Canada, reflects sales from October 14, 2022 through December 31, 2022 related to the TransGlobe Acquisition.

EMPLOYEES AND HUMAN CAPITAL RESOURCE MANAGEMENT

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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 the culture is built and represent the key expectations we have of our employees.

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.

As part of our sustainability effort, we plan to conduct and publish the results of an all-employee engagement survey in 2024.

As of December 31, 2023, we had 189 full-time employees, 91 of whom were located in Gabon, 34 in Egypt, 9 in Canada and 55 in Houston.

Likewise, there are 42 contractors in Gabon, 16 contractors in Egypt, 1 contractor in Canada and 21 contractors in Houston.

As of December 31, 2024, we had 230 full-time employees, 119 of whom were located in Gabon, 39 in Egypt, 11 in Canada, 1 in Cote d'Ivoire, 1 in Equatorial Guinea, 54 in Houston and 5 corporate employees based in London.

We also had 61 contractors in Gabon, 14 contractors in Egypt, 6 contractors in Canada and 24 contractors in Houston as of December 31, 2024.

We are not subject to any collective bargaining agreements, although some of the national employees in Gabon are members of the NEOP (National Organization of Petroleum Workers) union.

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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.

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.

We also plan to expand the benefit for our employees to participate in paid volunteering in company-approved activities, in certain areas of operation.

As part of this global effort, we also expect to publish details about this new benefit for employees.

Workplace environment is also crucial in attracting and retaining key talent.

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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 employs software tools and periodic employee training programs to promote security and information protection at all levels.

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.

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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.

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.

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.

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A material loss not fully covered by insurance could have an adverse effect on our financial position, results of operations or cash flows.

Question - is our practice to obtain any updates on country-specific regulations from local counsel?

Also, there was an issue with us not filing to be regulated locally for emissions, verses federally, in Canada.

Consider if that merits a mention somewhere.

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.

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• 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.

Numerous governmental departments and agencies issue rules and regulations binding on the crude oil, natural gas and NGLs industry, some of which carry substantial penalties for the failure to comply.

The regulatory burden on the crude oil, natural gas and NGLs industry increases our cost of doing business and our potential for economic loss.

Our exploration and production activities offshore Gabon are subject to Gabonese regulations.

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.

Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations.

In recent years, there have been indications that authorities were working or planned to work on a Gas Code and new Hydrocarbons Law.

Also, following the coup d’état of August 30, 2023, Gabon established a Transition Committee for the Restoration of Institutions, swore in General Brice Oligui Nguema as the President and appointed a Transition Government and tentatively plans to hold national, presidential and local elections in 2025.

Accordingly, the risk of legislation having a significant impact on petroleum operations being adopted during the Transition Period cannot be discarded.

The following is a summary of certain applicable regulatory frameworks in Gabon.

2014 Hydrocarbons Law - Up until 2014, the fiscal and regulatory framework governing the exploration and production of hydrocarbons in Gabon was notably unregulated.

Successive model contracts issued by the State of Gabon acted as guidelines;

all fiscal aspects of each contract were negotiable between the State of Gabon and exploratory parties, including work commitments and exploration costs for each PSC.

In September 2014, Law No.

11/2014, of August 28, 2014, came into force in Gabon (“2014 Hydrocarbons Law”).

The 2014 Hydrocarbons Law was not exhaustive;

it sought to provide a framework of governing principles and rules, applicable to both the exploratory and extracting industry of hydrocarbons, as well as the downstream sector, to be complemented by implementing regulations.

Under the Gabonese Civil Code (“Civil Code”), laws will not have retroactive effects unless they expressly or tacitly provide otherwise.

The Civil Code further provides that former laws continue to govern the effects of existing contracts, save in case of express or tacit derogation by the legislator and that, in any event, the application of a new law to existing contracts cannot modify the effects already produced by existing contracts under a former law, except via express derogation by the legislator.

The 2014 Hydrocarbons Law explicitly provided that establishment conventions, petroleum contracts, petroleum titles, mining concessions and exploitation permits concluded or granted by the State of Gabon prior to the date of its publication remained in force until their expiration date.

However, the 2014 Hydrocarbons Law further provided that unless such arrangements became consistent with the requirements of the 2014 Hydrocarbons Law, establishment conventions, mining concessions and exploitation permits in effect could not be extended or renewed.

Furthermore, the 2014 Hydrocarbons Law prohibited establishment conventions and mining concessions, and provided that the exploitation of new discoveries in areas covered by existing conventions and concessions would be required to be made in accordance with the 2014 Hydrocarbons Law.

2019 Hydrocarbons Law - The 2014 Hydrocarbons Law was repealed in its entirety by Law No.

002/2019, of 16 July 2019, published on 22 July 2019 (“2019 Hydrocarbons Law”).

As with the 2014 Hydrocarbons Law, the 2019 Hydrocarbons Law contains provisions applicable to both the upstream and downstream segments.

The regulatory burden on the crude oil, natural gas and NGLs industry increases our cost of doing business and our potential for economic loss.

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 are subject to the provisions of the 2019 Hydrocarbons Law, and its implementing regulations.

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 Africa 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.

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 since the implementation of the 2019 Hydrocarbons Law must include a clause providing that participation by the State of Gabon 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, that 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 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.

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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.

In addition, the 2019 Hydrocarbons Law 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.

In Harmattan, Canada, we now own production and working interests in certain facilities in the Cardium light oil and Mannville liquids-rich gas assets.

Harmattan is located approximately 80 kilometers north of Calgary, Alberta.

This property produces oil and associated natural gas from the Cardium and liquids-rich natural gas from zones in the Lower Mannville and Rock Creek formations at vertical depths of 1,200 to 2,600 meters.

The Harmattan property covers 46,100 gross acres of developed land and 29,300 gross acres of undeveloped land.

We also own a 100% working interest in a large oil battery and a compressor station where a majority of oil volumes are handled.

All gas is delivered to a third party non-operated gas plant for processing.

Our exploration and production activities in Canada are subject to Canadian federal and provincial regulations.

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.

Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations.

The following is a summary of certain applicable regulatory frameworks in Canada.

With the exception of the province of Manitoba, each provincial government in Western Canada owns most of the mineral rights to the oil and natural gas located within their respective provincial borders.

The Government of Alberta grants rights to explore for and produce oil and natural gas based on conditions set out in provincial legislation and regulations in exchange for a Crown Royalty share as set out in the Alberta Modernized Royalty Framework Guidelines, 2017 (as amended in 2023).

To develop oil and gas resources, producers must also have access rights to the surface lands required to conduct operations.

For private lands in Alberta, producers must either obtain consent of the private landowner or, where an agreement cannot be reached, a right of entry order issued under the Surface Rights Act (Alberta).

In addition to obtaining mineral and surface rights in Canada, producers may need to engage extensively with Indigenous groups.

Canadian federal and provincial governments have a constitutional duty to consult and, in some cases, accommodate Indigenous groups where a project might adversely impact a potential Indigenous rights and title claim.

The procedural aspects of the duty to consult are often delegated to project proponents.

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 Cabinet that a pipeline project is in the public interest will also likely be required under the Impact Assessment Act (Canada)(“IAA”).

Certain oil and gas projects were subject to federal environmental assessments prior to the Supreme Court of Canada finding the “designated projects” component of the IAA to be unconstitutional in a judgement released on October 13, 2023.

The federal government has yet to introduce legislative changes to the IAA clarifying the scope of federal environmental assessments following the Supreme Court of Canada’s ruling.

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.

An environmental impact assessment under the Environmental Protection and Enhancement Act (Alberta) will also likely be required.

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.

For example, the AER administers the Licensee Liability Management Rating Program, which is currently being phased out with implementation of the AER’s new Liability Management Framework (“LMF”), to ensure adequate security is available for a project to be decommissioned safely, with no harm to the public or the environment.

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.

One component of this regime is an emissions trading system for large industry.

The GGPPA allows provinces to either 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”), which came into effect on January 1, 2020, regulates emissions of heavy industry in line with federal standards.

On December 14, 2022, the Government of Alberta introduced several amendments to TIER which became effective January 1, 2023, broadening the scope of “large emitters” subject to TIER and strengthening facility specific benchmarks, among other things.

The Government of Alberta also enacted the Methane Emission Reduction Regulation (Alberta) on January 1, 2020, which, in line with AER Directive 060:

Upstream Petroleum Industry Flaring, Incinerating, and Venting (“AER Directive 060”) and AER Directive 017:

Measurement Requirements for Oil and Gas Operations sets vent gas limits for methane per month, which are monitored through the collection of representative measuring data.

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.

For example, in 2019 the Royalty Guarantee Act (Alberta) came into effect and provides that no major changes will be made to the current oil and gas royalty structure for a period of at least 10 years.

AER Directive 060 was updated in April 2022 and sets more stringent vent gas limits for equipment installed after January 1, 2022, with a phased in approach for equipment installed prior to that date.

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.

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 agencies, including EGPC, the Egyptian Natural Gas Holding Company ("EGAS") and the Ganoube El-Wadi Petroleum Holding Company ("GANOPE") (each the “government entity”) have been set up to help the MOP achieve its objectives.

Certain government agencies (“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.

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Ownership of Assets

Under the model concession agreements, the movable and immovable assets (other than lands, which become GANOPE/EGAS/EGPC's 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.

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.

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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.

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, the Department of Hydrocarbons, and Société Nationale d'Opérations Pétroliéres de la Cote d'Ivoire, 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.

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”).

released on October 13, 2023.

The federal government has yet to introduce legislative changes to the IAA clarifying the scope of federal environmental assessments following the Supreme Court of Canada’s ruling.

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.

An environmental impact assessment under the Environmental Protection and Enhancement Act (Alberta) will also likely be required.

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.

One component of this regime is an emissions trading system for large industry.

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 and has since been amended broadening the scope of “large emitters” subject to TIER and strengthening facility specific benchmarks, among other things.

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, which are monitored through the collection of representative measuring data.

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

Our exploration and production activities in Equatorial Guinea are subject to the applicable regulations of the country.

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.

Moreover, these laws and regulations could change in ways that could substantially increase our costs or affect our operations.

A draft of a new Hydrocarbons Law was distributed by the Ministry of Petroleum during 2023 for comment and a new General Tax Law is being reviewed by the Parliament, but it is still not possible to determine if any changes materially affecting our operations will be approved.

The following is a summary of certain currently applicable regulatory frameworks in 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.

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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.

Private crude oil companies have been allowed to conduct petroleum operations in Equatorial Guinea through PSCs signed by the minister responsible for petroleum operations on behalf of Equatorial Guinea.

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.

In addition, the national oil company of Equatorial Guinea, GEPetrol, holds, manages and takes participations in petroleum activities on behalf of Equatorial Guinea.

In 2006, the Parliament of Equatorial Guinea passed a new hydrocarbons law (“2006 Hydrocarbons Law”), which superseded the previous 1981 Hydrocarbons Law, as amended in 2000, incorporating not only the regime applicable to the exploration, appraisal, development and production of hydrocarbons, but also rules on their transportation, distribution, storage, preservation, decommissioning, refining, marketing, sale and other disposal.

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 2006 Hydrocarbons Law grants the ministry appointed to be responsible for petroleum operations (“Appointed EG Petroleum Ministry”) significantly broad regulatory, inspective and auditing powers concerning the performance of petroleum operations.

These include the powers to negotiate, sign, amend and perform all contracts entered into between the State of Equatorial Guinea and independent contractors, as well as the right to access all data and information required for the control of contractors and their activities, including free access to the locations and facilities where petroleum operations are conducted.

In addition, the Appointed EG Petroleum Ministry can also order (i) the suspension of petroleum operations;

(ii) the evacuation of persons from locations;

(iii) the suspension of the use of any machine or equipment;

and/or (iv) any other action it deems necessary or appropriate when the Appointed EG Petroleum Ministry determines that a given petroleum operation may cause injury to or death of persons, damage properties, or harm the environment, or whenever the national interest so requires.

Until June 2016, the Appointed EG Petroleum Ministry was the Ministry of Mines, Industry and Energy, whose organization and authority were granted under Decree No.

170/2005, of 15 August 2005.

In June 2016, the President of Equatorial Guinea appointed the EG MMH and the Minister of Industry and Energy, effectively splitting the Ministry of Mines, Industry and Energy into two ministries.

However, no legislation on the organization and authority of each ministry has been enacted, and, in effect, the EG MMH has been exercising the powers contained within the Hydrocarbons Law to the Appointed EG Petroleum Ministry.

This situation has not changed.

Also, in early 2023, Mr.

Gabriel Obiang Lima, who had been the Minister in charge of petroleum matters for several years, was moved to another Ministry and Mr.

Antonio Oburu, who had been the General Director of the National Oil Company (GEPetrol), became the head of the MMH.

Until now no materials changes in the enforcement of petroleum legislation has been felt.

All contracts signed with the State of Equatorial Guinea for the exploration and production of hydrocarbons have taken the form of PSCs.

A model PSC, approved along with the Hydrocarbons Law, must be used as the basis for any negotiation between independent contractors and the State of Equatorial Guinea.

Over time, however, revised copies of the model PSC, reflecting changes made during negotiations of certain PSCs, have been used for the negotiation of subsequent PSCs.

The Hydrocarbons Law and Petroleum Regulations provide the Appointed EG Petroleum Ministry with the power to award contracts for the exploration and production of hydrocarbons and decide whether the award is made by means of competitive international public tender or direct negotiation.

These contracts, however, which are to be negotiated by the Appointed EG Petroleum Ministry, shall only become effective after they have been ratified by the President of Equatorial Guinea and on the date of delivery to the contractor of a written notice of the President’s ratification.

In practice, however, this notification to operators has been provided by the Appointed EG Petroleum Ministry.

GEPetrol, established in 2001, is the national oil company of Equatorial Guinea and Sociedad Nacional de Gas de Guinea Equatorial (“Sonagas”), established in 2005, is the national gas company of Equatorial Guinea.

The Hydrocarbons Law provides that these national companies are exclusively owned by the State of Equatorial Guinea and must be supervised by the Appointed EG Petroleum Ministry.

Under the applicable laws, the State of Equatorial Guinea may elect to have, either directly or through a national company, a minimum interest of 20% in a PSC.

The State of Equatorial Guinea’s interest (through GEPetrol or otherwise) may be, and typically is, carried.

No costs are paid by the State of Equatorial Guinea or GEPetrol with respect to a carried interest.

The Hydrocarbons Law provides that the State of Equatorial Guinea (through GEPetrol or otherwise) will only be required to contribute to any cost for petroleum operations that it has a carried interest in from the period where it notifies the contractor that it no longer wants its interest carried.

In effect, however, the carry normally ends with the approval of the development and production of the asset subject to the PSC.

The terms and effects of the carry of an interest of the State of Equatorial Guinea (through GEPetrol or otherwise) are not clearly established in the Hydrocarbons Law or the Petroleum Regulations;

the contractor that carries the State of Equatorial Guinea’s interest is given the right to a percentage of the cost recovery oil pertaining to that interest, as agreed in each PSC.

The EG MMH, which is currently the appointed EG Petroleum Ministry, has been exercising the powers contained within the Hydrocarbons Law.

ENVIRONMENTAL REGULATIONS

Our operations are subject to various federal, state, local and international laws and regulations, including laws and regulations in Gabon, Equatorial Guinea, Egypt and Canada, governing the discharge of materials into the environment or otherwise relating to environmental protection or pollution control.

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 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.

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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, in April 2016, 195 nations, including Gabon, Equatorial Guinea, Egypt, Canada and the U.S., signed and officially entered into an international climate change accord (the “Paris Agreement”).

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.

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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.

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 COP 28.

However, a few oil companies operating in Gabon signed the Oil and Gas Decarbonization Charter at COP 28.

One of them is ending its operations in Equatorial Guinea upon the expiration of its petroleum contracts.

On October 5, 2016, Canada ratified the Paris Agreement by a vote in Parliament.

In August 2017, the U.S.

Department of State officially informed the United Nations of the U.S.’ intent to withdraw from the Paris Agreement, with such withdrawal becoming effective in November 2020.

However, on January 20, 2021, President Biden issued written notification to the United Nations of the U.S.’ intention to rejoin the Paris Agreement, which took effect on February 19, 2021, and on April 22, 2021, President Biden announced a target for the US to achieve a 50-52% reduction from 2005 levels in economy-wide GHG emissions by 2030.

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.

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.

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Egypt was also host to 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 (“UNDP”), 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.

Through 2022 to 2023, Egypt announced and signed further partnerships in the energy sector, particularly for green hydrogen and ammonia production.

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.

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There are no further guidelines on whether and how it will apply to the petroleum industry.

In addition, following the coup d’état on August 30, 2023 in Gabon, the establishment of a Transition Committee for the Restoration of Institutions, the swearing in of General Brice Oligui Nguema as President and the appointment of a Transition Government, with in view of holding elections in 2025 (tentative date), it is still unclear whether and how any environmental regulation having a material impact on petroleum operations will be adopted during the Transition Period, and how the current regulations will be implemented.

Any significant increase in the regulation or enforcement of environmental issues by Gabon, Equatorial Guinea or Egypt could have a material effect on us.

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.

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What changed 10-K

Item 1. Business