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Item 5. Market for Registrant’s Common Equity

2025-03-17 compared with 2024-03-15 · 291 added, 379 removed, 159 unchanged (81% of the section changed)

3 unchanged sentences

This number does not include beneficial or other owners for whom common stock may be held in “street” names.

On February 14, 2023, we announced that our board of directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter commencing in the first quarter of 2023 and continued throughout the year.

The following table is a schedule of our dividends paid during 2024:

Dividend Payment Date

Amount per common share

March 31, 2023

March 24, 2023

June 23, 2023

September 22, 2023

August 25, 2023

December 21, 2023

November 24, 2023

Dividend Payment Date Amount per common share Record Date

March 28, 2024 $ 0.0625 March 8, 2024

June 21, 2024 $ 0.0625 May 17, 2024

September 20, 2024 $ 0.0625 August 23, 2024

December 20, 2024 $ 0.0625 November 22, 2024

Aggregate per share amount paid in 2024 $ 0.2500

In connection with the RBL facility, we are required to provide a cash flow projection prior to any distribution, share buyback, or stock repurchase.

As long as a group liquidity test is above the required ratio outlined in the RBL facility agreement, and no event of default exists, we may make distributions, buyback shares, or repurchase stock without further approval.

In the event the liquidity test is not met, an approval or waiver would need to be obtained from Glencore in order to make distributions, buyback shares, or repurchase stock.

For the year ended December 31, 2023, no specific approval or waivers were required to make distributions or repurchase stock.

In connection with the 2025 RBL Facility, we are required to provide a group liquidity forecast prior to any distribution, share buyback, or stock repurchase (each, a “Distribution”).

The forecast must include the amount of Distribution expected in the forecast period.

Provided there is no borrowing base deficiency, and no event of default results or exists, we may make Distributions without further approval as long as (1) the current forecast is above the required ratio and the proposed Distribution, aggregated with the amount declared or paid in any three months within the forecast period, does not exceed 110% of the estimated amount for that period, or (2) we provide an updated forecast that is above the required threshold taking into account the proposed Distribution and the expected Distribution in any three-month period within the relevant forecast period.

In the event the liquidity test is not met, an approval or waiver would need to be obtained from the Lenders to make a Distribution.

Cash dividends during the expected period of the refurbishment of the FPSO in Cote d’Ivoire, if any are declared, shall not be more than $0.26 per share.

For the year ended December 31, 2024, no specific approval or waivers were required to make Distributions.

To the extent we have adequate cash on hand and cash flows from operations, we will consider paying additional cash dividends on a quarterly basis;

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Stockholder returns over the indicated period may not be indicative of future stockholder returns.

2019 2020 2021 2022 2023 2024

SPDR S&P Oil & Gas Exploration and Production $ 100 $ 62 $ 104 $ 151 $ 156 $ 152

1 unchanged sentence

VAALCO Energy, Inc.

$ 100 $ 80 $ 145 $ 210 $ 220 $ 217

Unregistered Sales of Equity Securities and Use of Proceeds

There were no sales of unregistered securities during the quarter ended December 31, 2023 that were not previously reported on a Current Report on Form 8-K.

There were no sales of unregistered securities during the year ended December 31, 2024 that were not previously reported on a Current Report on Form 8-K.

Issuer Repurchases of Common Stock

The Company has implemented a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise under the Securities Exchange Act of 1934.

The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over a maximum period of up to 20 months.

Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.

The below table shows the repurchases of equity securities related to the share repurchase program during the quarter ended December 31, 2023:

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Programs

Maximum Amount that May Yet Be Used to Purchase Shares Under the Program

October 1, 2023 - October 31, 2023

November 1, 2023 - November 30, 2023

December 1, 2023 - December 31, 2023

The Company previously implemented a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise under the Exchange Act.

The 10b5-1 Plan provided for an aggregate purchase of currently outstanding common stock of up to $30 million over a maximum period of up to 20 months.

Payment for shares repurchased under the share buyback program were funded using the Company's cash on hand and cash flow from operations.

The share buyback program was completed on March 12, 2024.

The below table shows the repurchases of equity securities related to the share repurchase program during the fiscal year ended December 31, 2024:

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Programs

Maximum Amount that May Yet Be Used to Purchase Shares Under the Program

January 1, 2023 - January 31, 2023

February 1, 2023 - February 28, 2023

March 1, 2023 - March 31, 2023

April 1, 2023 - April 30, 2023

May 1, 2023 - May 31, 2023

June 1, 2023 - June 30, 2023

July 1, 2023 - July 31, 2023

August 1, 2023 - August 31, 2023

September 1, 2023 - September 30, 2023

October 1, 2023 - October 31, 2023

November 1, 2023 - November 30, 2023

December 1, 2023 - December 31, 2023

The following table shows the repurchases of our equity securities related to our share repurchase program after December 31, 2023 through March 8, 2024:

Total Number of Shares Purchased

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Programs

Maximum Amount that May Yet Be Used to Purchase Shares Under the Program

Period Total Number of Shares Purchased Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Programs Maximum Amount that May Yet Be Used to Purchase Shares Under the Program

January 1, 2024 - January 31, 2024 446,366 $ 4.48 446,366 $ 3,516,205

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March 1, 2024 - March 12, 2024 347,137 $ 4.33 347,137 $ —

Total 1,267,603 1,267,603

Management ’ s Discussion and Analysis of Financial Condition and Results of Operations

The following management ’ s discussion and analysis describes the principal factors affecting our capital resources, liquidity, and results operations.

The following management ’ s discussion and analysis describes the principal factors affecting our capital resources, liquidity, and results of operations.

This management ’ s discussion and analysis should be read in conjunction with the accompanying Financial Statements and related notes, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this Annual Report.

For discussion related to changes in financial condition and results of operations for 2023 as compared with 2022, refer to Part II, Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2022 Form 10-K, which was filed with the SEC on April 6, 2023.

Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2023 Form 10-K, which was filed with the SEC on March 15, 2024.

Certain statements in our discussion below are forward-looking statements.

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Risk Factors ” for further details about these statements.

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.

For further discussion of our four operating segments see “ Item 1.

Business – Segment and Geographical Information – “ Gabon Segment ”, " Egypt Segment", " Canada Segment", and “ Equatorial Guinea Segment ”" .

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

The negotiations were kick 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 the PSC 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 Arrangement with TransGlobe in 2022, 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).

See Note 4 to the consolidated financial statements for further discussion regarding the Arrangement.

Recent Operational Updates

VAALCO completed its 2021/2022 drilling campaign in the fourth quarter of 2022.

We are currently evaluating locations and planning for the next drilling campaign at Etame that is expected to occur late in 2024.

In October 2022, VAALCO successfully completed its transition to a Floating Storage and Offloading vessel (“FSO”) and related field reconfiguration processes.

This project provides a low cost FSO solution that increases the storage capacity for the Etame block and improved operational performance.

The Company will continue to focus on operational excellence, including production uptime and enhancement in 2024 to minimize decline until the next drilling campaign.

At the end of December 2023, all wells were online from the end of 2022 as the gas lift compression system was successfully commissioned.

This gas lift compression system increased the production and the reliability of two subsea wells, positively impacting our volumes for the year ended December 31, 2023.

Gas lift compression and subsea wells remained online with a high level of reliability through the year ended December 31, 2023.

The focus during the beginning of 2023 was continued production optimization of the new flow line configurations at the Etame Facility, as all production transits through the Etame platform for final processing before being pumped to the FSO.

Since the field reconfiguration in 2022, a better understanding of the field’s operating parameters, through the new central processing facility (CPF) on Etame, has resulted in a more efficient and cost effective flow assurance program.

Continued optimization and understanding of the post reconfiguration process dynamics of the Etame platform, have maintained a very high uptime availability of Etame Facility and in turn the complete Etame field during the second quarter.

Combining this with individual well and facility chemical injection optimization and facility pipeline pigging adjustments both on frequency of pigging and flow path targeting, has increased production through decrease in pipeline internal buildup and resulting drop in pipeline back pressure, this in turn has provided more stable operations resulting in lower downtime.

Through the fourth quarter of 2023, this continues to be a focus with positive results in production rates and uptime.

Preventative maintenance activities remained at levels prior to the field reconfiguration, as the focus was on steady state operation following project completion.

Equipment reliability and availability remain at high levels.

The actual percentages of Corrective Maintenance performed versus Preventative Maintenance performed remain well within VAALCO and Industry Best Practice standards.

Major planned maintenance was carried out on Etame Power generation turbines.

Charter Agreement for the Floating Storage and Offloading Unit in Gabon

In August of 2021, we and our co-venturers at Etame approved the FSO Agreements with World Carrier to replace the existing FPSO with an FSO.

The FSO Agreements required a prepayment of $2 million gross ($1.2 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net to VAALCO) in 2022 of which $6 million will be recovered against future rentals.

On October 19, 2022, the replacement of the existing FPSO was completed and we signed the final acceptance certificate, at which time control of the FSO vessel transferred to us.

The new FSO has been named “Teli” (renamed from “Cap Diamant”) and is on site and accepting oil at the Etame Marin block.

Total field conversion expenses were $122 million gross ($77 million net to VAALCO).

The FPSO charter we were party to prior to the FSO installation was set to expire in September 2022, but on September 9, 2022 we signed an addendum to the FPSO contract which extended the use of the FPSO through October 4, 2022, and ratified certain decommissioning and demobilization items associated with exiting the contract.

Pursuant to the addendum, VAALCO Gabon agreed to pay the charterer day rate of $150,000 from August 20, 2022 through October 4, 2022 and other demobilization fees totaling $15.3 million on a gross basis ($8.9 million net to VAALCO).

The demobilization of the FPSO was carried out from October 5, 2022 through to November 19, 2023.

This included the cleaning and removal of waste from the Cargo and Slop Tanks.

In the fourth quarter of 2023, the joint operating group in Gabon reached a settlement agreement with Tinworth to release the joint operating group from any further obligation pertaining to the former FPSO.

The signed agreement, dated December 12, 2023, called for the group to pay an additional $8 million gross ($4.7 million net to VAALCO) to Tinworth in exchange for the release.

The payment was made on December 22, 2023.

Based on this and the prior expense incurred earlier in the year, VAALCO reported $7.5 million in FPSO Demobilization costs on the income statement for the year ended December 31, 2023.

The sail date on the FPSO was November 19, 2023.

VAALCO continued to use the EDC-64 rig in the Eastern Desert drilling campaign.

We continue to drill an average of two wells per month with the EDC-64 rig and we drilled 18 wells in year 2023.

The SGZ-6X well remains shut-in.

We continue to evaluate our strategic options.

There was no production from South Ghazalat due to the SGZ-6X remaining shut-in.

There is a planned workover for this well in 2024 to resume production.

A summary of the Egyptian drilling campaign's impact during 2023 is presented below:

VAALCO Egypt 2023 Wells

Penetrated Pay Zones

Completion Zone

Perforation Interval (ft)

IP-30 Rate (BOPD)

Hydraulic Frac

Asl-A, B, D, E and F

Asl-B1 and B2

HE-5 Injector

Asl-B1 and B2

Hydraulic Frac

Temporarily Abandoned

Asl-A, B, D and E

Asl-D, E, F and G

Asl-A, B and D

Nukhul and Redbed

Nukhul, Thebes and Redbed

Plugged & Abandoned

Hydraulic Frac

Early in 2023, two wells, the 04-10-29-03W5 and the 04-19-29-3W5, were tied in.

Both wells are now online and producing.

The 2023 drilling campaign commenced in January 2023 with the drilling of 12-12-30-4W5, spudded on January 28, 2023.

The well was drilled to a total depth of 22,024 feet.

The second well of the program, 16-30-29-3W5, was spudded on February 22, 2023, and drilled to a total depth of 14,446 feet.

The two wells were completed between late March and early April and tied in and equipped in April and early May.

12-12-30-4W5 was put online in late April, and 16-30-29-3W5 was put online in early May with cycle times that were significantly less than historical cycle times.

The wells free flowed in the months of May and June.

In early July, the pump and rods were run on both wells.

Both wells continue to produce and both wells continued to exceed expectations during the fourth quarter of 2023.

A summary of the Canada drilling campaign's impact during 2023 is presented below:

VAALCO Canada 2023 Wells

Penetrated Pay Zones

Completion Zone

Perforation Interval (ft)

IP-30 Rate (BOPD)

Upper Bioturbated Cardium

118 Stg x 15T Hydraulic Fracture Treatment

Upper Bioturbated Cardium

55 Stg x 15T Hydraulic Fracture Treatment

CAPITAL RESOURCES AND LIQUIDITY

Our cash flows for the years ended December 31, 2023 and 2022 are as follows:

Twelve Months Ended December 31,

Increase (Decrease) in 2023 over 2022

We are an independent energy company headquartered in Houston, Texas engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs.

We have a diversified African-focused asset portfolio in Gabon, Egypt, Cote d'Ivoire, Equatorial Guinea and Nigeria, as well as producing properties in Canada.

For further discussion of our five operating segments see “Item 1.

Business – Segment and Geographical Information.”

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

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

Over the past years,

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

Recent Developments and Outlook

2024 Acquisition

On April 30, 2024, we completed the acquisition of Svenska Petroleum Exploration Aktiebolag, a company incorporated in Sweden whereby we acquired all of the issued shares in the capital of Svenska and Svenska became a direct, wholly-owned subsidiary of the Company (“Svenska Acquisition”) for a net adjusted purchase price of $40.2 million.

The purchase price was funded with the Company's cash on hand.

As a result of the Svenska Acquisition, we acquired Svenska’s primary asset:

a 27.39% non-operated working interest in the deepwater producing Baobab field in Block CI-40, offshore Cote d’Ivoire in West Africa.

We also acquired a 21.05% non-operated working interest in OML 145, a non-producing discovery located offshore of Nigeria that is not expected to be developed at this time.

Capital Program

We expect our 2025 capital program to range between $270 million to $330 million, assuming normal operating conditions, that prioritizes free cash flow generation and meaningful return of capital to shareholders.

The program includes estimated spending of approximately between $115 million to $135 million for Gabon, $30 million to $40 million for Egypt, $8 million to $13 million for Canada, $1 million to $3 million for Equatorial Guinea, $115 million to $135 million for Cote d'Ivoire for oil and natural gas development and $1 million related to corporate and other capital costs.

The foregoing amounts related to Etame projects in Gabon do not include amounts funded by the non-operating partners.

See further discussion below under “Capital Resources, Liquidity and Cash Requirements” for further discussion on the capital spending for each of our operating segments.

Commodity Prices

Prices for crude oil and condensate, NGLs and natural gas have historically been volatile.

This volatility is expected to continue due to the many uncertainties associated with the worldwide political and economic environment and the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors.

Significant changes in oil and natural gas prices have a material impact on our liquidity.

Declining commodity prices negatively affect our operating cash flow but have a positive indirect effect on operating expenses.

The inverse is also true during periods of rising commodity prices.

To mitigate some of the risk inherent in oil and natural gas prices, we have utilized various derivative instruments to hedge commodity price risk.

RESULTS OF OPERATIONS

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

We reported net income for the year ended December 31, 2024 of $58.5 m illion compared to a net income of $60.4 million for the year ended December 31, 2023.

The year-over-year decrease in net income was due to higher depreciation, depletion and amortization expense, production expenses and credit losses during the year, partially offset by the increase in revenues and a bargain purchase gain related to the Svenska acquisition.

Further discussion of results by significant line item follows.

Year Ended December 31, Increase/

2024 2023 (Decrease)

(in thousands except per Boe information)

Net crude oil, natural gas, and NGLs sales volume (MBoe) 7,262 6,832 430

Average crude oil, natural gas and NGLs sales price (per Boe) $ 65.64 $ 65.83 $ (0.19)

Net crude oil, natural gas, and NGLs revenue $ 478,988 $ 455,066 $ 23,922

Operating costs and expenses:

Production expense 163,500 153,157 10,343

FPSO demobilization and other costs — 7,484 (7,484)

Exploration expense 48 1,965 (1,917)

Depreciation, depletion and amortization 143,034 115,302 27,732

General and administrative expense 29,684 23,840 5,844

Credit (recovery) losses and other 6,304 (4,906) 11,210

Total operating costs and expenses 342,570 296,842 45,728

Other operating income (expense), net 78 433 (355)

Operating income $ 136,496 $ 158,657 $ (22,161)

The revenue changes between the years ended December 31, 2024 and 2023 identified as related to changes in price or volume are shown in the table below:

(in thousands)

Net cash provided by operating activities before changes in operating assets and liabilities

Net change in operating assets and liabilities

Net cash provided by (used in) continuing operating activities

Net cash used in discontinued operating activities

Net cash provided by (used in) operating activities

Net cash provided by (used in) investing activities

Net cash provided by (used in) in financing activities

Effects of exchange rate changes on cash

Net change in cash, cash equivalents and restricted cash

The $54.9 million increase in net cash provided by our operating activities before changes in operating assets and liabilities for the year ended December 31, 2023 compared to the same period of 2022 was due to higher pricing, more production and the increased number of producing wells.

The net increase in changes provided by operating assets and liabilities of $39.8 million for the year ended December 31, 2023 compared to the same period of 2022 was primarily related to decreases in accounts with joint venture owners, other receivables and foreign income taxes receivable partially offset by changes in accounts payable and accrued liabilities.

The $26.0 million increase in net cash used in investing activities during the year ended December 31, 2023 was due to decreases in cash capital spending in 2023.

In 2022 we incurred significant capital for the 2021/2022 Etame drilling campaign and the Etame field reconfiguration.

In 2023 capital spending for the drilling program in Egypt and Canada was less due to the lower per well costs for onshore wells is than Etame’s offshore wells and there were no costs associated with field reconfiguration in 2023.

Net cash used in financing activities during the year ended December 31, 2023 included $26.8 million dividends paid to common shareholders, $23.6 million for treasury stock purchases made under our stock repurchase plan, or as a result of tax withholding on options exercised and vested restricted stock as discussed in Note 17 to our consolidated financial statements, and $7.2 million related to principal finance lease payments partially offset by $0.7 million in proceeds from options exercised.

Price $ (1,376)

Volume 28,338

Total net revenue $ 23,922

(1) The Other in the table above includes revenues attributed to carried interests.

The table below shows net production, sales volumes and realized prices for both years.

Year Ended December 31,

Net crude oil, natural gas and NGLs production (MBoe) 7,296 6,833

Net crude oil, natural gas and NGLs sales (MBoe) 7,262 6,832

Average realized crude oil, natural gas and NGLs price ($/Boe) $ 65.64 $ 65.83

Average Dated Brent spot price* ($/Bbl) $ 80.52 $ 82.49

* Average of daily Dated Brent spot prices posted on the U.S.

Energy Information Administration website.

Costs and Expenses 2024 2023 % Change 2024 vs.

Production expense, excluding offshore workovers ($/BOE) $ 22.50 $ 22.42 — %

Depreciation, depletion and amortization ($/BOE) $ 19.69 $ 16.88 17 %

General and administrative expense, excluding stock-based compensation ($/BOE) $ 3.48 $ 3.49 — %

Crude oil, natural gas and NGLs net revenues increased $23.9 million, or approximately 5%, during the year ended December 31, 2024 compared to the same period of 2023.

The revenue increase is primarily attributable to revenues recognized within the Cote d'Ivoire segment during the year ended December 31, 2024 that were not present in the prior period.

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year.

The Company’s Gabon segment contributed $206.0 million of revenue to the Company’s total revenue during the year ended December 31, 2024.

This compares to the $260.3 million of revenue contributed by the segment during the year ended December 31, 2023.

The decrease in revenues is primarily due to lower sales volume in Gabon.

The total sales volume in Gabon for the year ended December 31, 2024 was 2,584 MBbls or 612 MBbls lower than the sales volumes of 3,196 MBbls in the same period in 2023.

Further, we had a decrease in the Gabon average realized price per barrel received during the year ended December 31, 2024 of $78.81 per barrel (Bbl) compared to the price received in 2023 of $79.80 per Bbl.

Our share of crude oil inventory, excluding royalty barrels, was approximately 267,754 barrels and 68,766 barrels at December 31, 2024 and 2023, respectively.

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC.

The Company’s Egypt segment contributed $146.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024.

This compares to the $161.0 million of revenue contributed by the segment during the year ended December 31, 2023.

The decrease in revenues was primarily due to the decrease in sales volumes during the year ended December 31, 2024 to 2,585 MBbls compared to 2,771 MBbls during the same period in 2023.

The average realized price received in Egypt was $56.47 per Bbl during the year ended December 31, 2024, which was also lower compared to the $58.11 per barrel received in 2023.

At December 31, 2024, the Company’s Egypt segment had zero barrels in oil inventory.

Crude oil sales in Canada are normally sold through pipelines to a third party.

The Company’s Canadian segment contributed $32.0 million of revenue to the Company’s total revenue for the year ended December 31, 2024.

This compares to the $33.7 million of revenue contributed by the Canada Segment during the year ended December 31, 2023.

The decrease in revenues is due to the lower average realized sales price received during the year ended December 31, 2024 of $36.77 per MBoe or a decrease of $1.79 per Boe from the $38.92 per Boe received during the same period in 2023.

The decrease in the average realized price was offset by the increase in sales volumes during the same period.

In Canada, the total sales volumes for the year ended December 31, 2024 was 870 MBoe or 5 MBoe higher than the 865 MBoe sold during the year ended December 31, 2023.

Cote d'Ivoire

Crude oil sales in Cote d’Ivoire are sold through a marketing contract with an international oil trading company which offers the cargo shipments to buyers, mainly refineries, around the world.

The Company's Cote d’Ivoire Segment contributed $95.1 million of revenue to the Company’s total revenue during the year ended December 31, 2024.

Total sales volumes in Cote d'Ivoire for the year ended December 31, 2024 was 1,223 MBbls and the average realized sales price received was $77.74 per barrel.

Production expenses increased $10.3 million , or approximately 7%, to $163.5 million in the year ended December 31, 2024 compared to the same period of 2023.

The increase in production expense was primarily driven by the crude oil inventory acquired in the Svenska Acquisition that was recorded at fair value upon acquisition and lower of cost or net realizable value in subsequent periods.

In addition, VAALCO has seen inflationary pressure on personnel and contractor

In February 2024, the government in Gabon enacted new regulation which has resulted in an increase to withholding taxes on foreign supplied goods and services.

On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 2024 decreased to $22.48 per barrel from the prior year of $22.59 per barrel primarily as a result of higher production volumes for the current period.

FPSO demobilization costs decreased $7.5 million, or 100% , to zero in the year ended December 31, 2024 compared to the same period of 2023.

In 2023, it was determined that there was additional normally occurring radioactive material (NORMs) waste than anticipated connected to the FPSO from the Contractors' usage.

As such, VAALCO and JOA partners incurred an additional $7.5 million (net to VAALCO) in decommissioning fees, which was reported as a separate line item on the income statement.

These costs were incurred to retire the FPSO as we transitioned the Etame block to the FSO.

Exploration expen se s decreased $1.9 mi llion, or approximately 98%, in the year ended December 31, 2024 compared to the same period of 2023 due primarily to the abandonment of the Egyptian East Arta - 54 appraisal well and the abandonment of the NWG-5C1 appraisal well in 2023.

Depreciation, depletion and amortization increased $27.7 million, or approximately 24%, in the year ended December 31, 2024 compared to the same period of 2023.

The increase in depreciation, depletion and amortization expense is due primarily to the addition of Cote d'Ivoire related to the Svenska Acquisition partially offset by lower depletable costs in Gabon, Egypt, and Canada.

General and administrative expenses increased $5.8 million, or approximately 25%, in the year ended December 31, 2024 compared to the same period of 2023.

The increase in general and administrative expenses is primarily due to professional fees, accounting and legal services, and salaries and wages.

Credit loss and other allowances - Credit loss and other expense increased $11.2 million, or approximately 228%, in the year ended December 31, 2024 compared to the same period of 2023.

The increase in credit losses and other for the year ended December 31, 2024, is primarily attributable to the receivables with EGPC regarding the settlement of these receivables owed to the Company.

During the year ended December 31, 2023, the decrease in credit loss and other allowances was primarily due to two credit loss and other allowance reversals in 2023.

These two reversals were partially offset by a credit loss and other allowance adjustment in Egypt.

Derivative instruments gain (loss), net is attributable to our commodity instruments as discussed in Part IV, Item 15., Note 10.

Derivatives and Fair Value to the Consolidated Financial Statements.

During the years ended December 31, 2024 and 2023, we recognized net realized losses of $0.5 million and $0.1 million, respectively, and unrealized losses of $0.2 million and an unrealized gain of $0.4 million, respectively, or a total net derivative losses of $0.7 million and net derivative gain of $0.2 million, respectively.

Derivative losses for 2024 are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the year ended December 31, 2024.

Our derivative instruments currently cover a portion of our production through September 2025.

Interest (expense) income, net decreased $2.7 million to an expense of $3.7 million for the year ended December 31, 2024 from an expense of $6.5 million during the same period in 2023.

The decrease of net interest expense for the year ended December 31, 2024 primarily results from a decrease in our amortization of debt issue costs and commitment fees incurred on the RBL Facility partially offset by interest income.

Other (expense) income, net increased $4.9 million to an expense of $5.8 million for the year ended December 31, 2024 from an expense of $0.9 million for the year ended December 31, 2023.

Other (expense) income, net normally consists of foreign currency losses as discussed in Part IV, Item 15., Note 2.

Summary of Significant Accounting Policies to the Consolidated Financial Statements.

However, for the year ended December 31, 2024, other (expense) income, net, also included $3.9 million of transaction costs associated with the Svenska Acquisition.

Income tax expense (benefit) f or the year ended December 31, 2024 was an expense of $81.3 million.

This is comprised of $98.9 million of current tax expense and a deferred tax benefit of $17.6 million.

Income tax expense for the year ended December 31, 2023 was an expense of $89.7 million.

This was comprised of $92.6 million of current tax expense and a deferred tax benefit of $2.9 million.

The current tax expense in both periods is primarily attributable to our operations in Gabon, Egypt, Canada and Cote d'Ivoire.

The income tax expense is higher in 2024 than income tax for the comparable 2023 period as a result of higher revenues.

See Part IV, Item 15., Note 8.

Income Taxes to the Consolidated Financial Statements for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

Capital Expenditures

During 2023, we had accrual basis expenditures attributable to continuing operations of $72.6 million, that includes $17.0 million for Gabon, $37.9 million for Egypt, $16.8 million for Canada and $1.0 million for the corporate offices, compared to $434.4 million for 2022.

Capital expenditures in 2023 were attributable to expenditures primarily related to the payments for the 2023 drilling campaigns in Egypt and Canada.

The 2022 capital expenditures include TransGlobe assets acquired for stock.

The difference between capital expenditures and the property and equipment expenditures reported in the consolidated statements of cash flows is attributable to changes in accruals for costs incurred but not yet invoiced or paid on the report dates.

Capital expenditures in 2022 were attributable to expenditures related to the 2021/2022 drilling program, the Etame field reconfiguration and drilling activity in Egypt and Canada.

Regulatory and Joint Interest Audits

We are subject to periodic routine audits by various government agencies, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements.

See Note 12 to the Consolidated Financial Statements for further discussion.

During 2024, we had accrual basis expenditures attributable to operations of $109.4 million, that includes $22.6 million for Gabon, $11.4 million for Egypt, $25.8 million for Canada, $44.4 million for Cote d'Ivoire, $0.6 million for Equatorial Guinea and $4.6 million for the corporate offices, compared to $72.6 million for 2023.

Capital expenditures in 2024 were attributable to expenditures primarily related to the new wells drilled as part of the drilling campaign in Canada, the workover and drilling program in Egypt and the expenditures associated with the preparation of the FPSO dry dock project in Cote d'Ivoire.

Capital expenditures in 2023 were primarily related to the payments for the 2023 drilling campaigns in Egypt and Canada.

Recent Operational Updates

The Company secured a drilling rig in December 2024 in conjunction with its 2025/2026 drilling program, which is planned to begin in mid-2025 to drill multiple development wells, and appraisal or exploration wells, as well as to perform workovers, with options to drill additional wells.

We are planning on multiple wells in both the Etame field and at our SEENT platform, and a re-drill and several workovers in the Ebouri field to access production and reserves that were previously shut in and removed from proved reserves due to the presence of hydrogen sulfide.

The Company focused on enhancing production in 2024 through a series of planned workovers.

The EA-55 well, drilled in October 2023, was completed and put online in January 2024.

During the year, the planned workover program for 2024 was completed for 12 wells, including the K-81 well recompletion at the start of the first quarter of 2024, which was a carry-over from our 2023 drilling activity.

The focus of the workover activities was to achieve peak production from the wells, significant improvements on the rate of production, and enhance production efficiency.

The Company deferred its 2024 drilling during the year to work up a robust drilling program.

We have contracted a rig and commenced with the drilling of two wells December 2024.

The first of the two wells was also successfully completed in December 2024, while the second well is expected to come on line in early 2025.

Cote d'Ivoire

As previously discussed, the FPSO will be placed in dry dock in early 2025 for planned maintenance and upgrades.

It ceased hydrocarbon production as scheduled on January 31, 2025 and the final lifting of crude oil from the FPSO took place on February 5, 2025.

The project team has commenced mobilization efforts, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO.

The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departure from the field around March 2025.

Significant development drilling is expected to begin in 2026 after the FPSO is expected to return to service with meaningful additions to production from the main Baobab field in CI-40, as well as a potential future development of the Kossipo field, which is also on the license.

We successfully drilled and completed four wells in 2024, all of which have been producing during the year.

The wells were drilled with longer 2.75 mile laterals to improve the economics of the program.

The new wells drilled resulted in a change in the production mix in Canada from about 60% liquids during the first quarter to about 75% after the wells came online with a lower gas-oil ratio.

In early November 2024, a fifth well was drilled and we plan to put the well online in early 2025.

Commodity Price Hedging

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We do not anticipate any substantial changes in our hedging policy.

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

At December 31, 2023 and 2022, we had unrestricted cash of $121.0 mill ion and $37.2 million, respectively.

Please see Part IV, Item 15., Note 10.

Derivatives and Fair Value in our Consolidated Financial Statements for more information on the related hedges.

At December 31, 2024 and 2023, we had unrestricted cash of $82.6 million and $121.0 million , respectiv ely, which as of certain dates, exceeded Federal Deposit Insurance Corporation insurance limits.

We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible.

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Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

We currently sell our crude oil production from Gabon under a crude oil sales and marketing agreement ("COSMA") with Glencore.

Under the COSMA all oil produced from the Etame G4-160 Block offshore Gabon from August 2022 through the final maturity date of the Facility, expected to be May 15, 2027, will be bought and marketed by Glencore, with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Sales with Glencore are normally settled 30 days from the delivery date.

Revenues associated with the sales of our crude oil in Egypt are recognized by reference to actual volumes sold and quoted market prices in active markets for Dated Brent, adjusted according to specific terms and conditions as applicable per the sales contracts.

Revenue is measured at the fair value of the consideration received or receivable.

For reporting purposes, we record the EGPC’s share of production as royalties which are netted against revenue.

With respect to taxes in Egypt, our income taxes under the terms of the Merged Concession Agreement are the liability of TransGlobe Petroleum International ("TGPI"), a wholly-owned indirect subsidiary of VAALCO.

TGPI's income taxes are paid by EGPC on behalf of TGPI out of EGPC’s production entitlement.

The income taxes paid to the Arab Republic of Egypt on behalf of TGPI are recognized as oil and gas sales revenue and income tax expense for reporting purposes.

Terms of settlement for sales to EGPC are within 30 days from the delivery date.

Revenues from the sale of crude oil, natural gas, condensate and NGLs in Canada are recognized by reference to actual volumes delivered at contracted delivery points and prices.

Prices are determined by reference to quoted market prices in active markets for crude oil, natural gas, condensate, and NGLs based on product, each adjusted according to specific terms and conditions applicable per the sales contracts.

Revenues are recognized net of royalties and transportation costs.

Revenues are measured at the fair value of the consideration received or receivable.

Settlement of accounts receivable in Canada occur on the 25th of the following month after production.

Capital Resources, Liquidity and Cash Requirements

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Our future success in growing proved reserves, production and balancing the long-term development of our assets with a focus on generating attractive corporate-level returns will be highly dependent on the capital resources available to us.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations, including the addition of our Egypt and Canada segments, to support our current cash requirements, including the FSO charter, drilling programs, as well as transaction expenses and capital and operational costs associated with our business segments' operations.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances, cash flow from operations and our 2025 RBL Facility to support our current cash requirements during the next 12 months and beyond, including the FSO charter, drilling programs, as well as transaction expenses and capital and operational costs associated with our business segments' operations.

However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends for other similar transactions depends on operating and economic conditions, some of which are beyond our control.

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Merged Concession Agreement

For information on the Merged Concession Agreement, see Note 12 to the Consolidated Financial Statements.

For information on the Merged Concession Agreement, see Part IV, Item 15., Note 12.

Commitments and Contingencies to the Consolidated Financial Statements.

RBL Facility Agreement and Available Credit

For information on our RBL Facility Agreement and Available Credit, see Note 13 to the Consolidated Financial Statements.

For information on our RBL Facility Agreement and Available Credit, see Part IV, Item 15., Note 13.

Debt to the Consolidated Financial Statements.

For information on our 2025 Facility Agreement and Available Credit, see Part IV, Item 15., Note 13.

Debt and Note 20.

Subsequent Events to the Consolidated Financial Statements.

Cash Requirements

Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, the TransGlobe acquisition transaction costs, dividend payments, funding of our share buyback program, merged concession agreement, future lease payments and abandonment funding, each of which is discussed in further detail below.

Potential Acquisition - On February 29, 2024, we entered into a Share Purchase Agreement to purchase all of the issued shares in the capital of Svenska for $66.5 million in cash, subject to adjustment as described in the Share Purchase Agreement.

Pursuant to the terms and subject to the conditions of the Share Purchase Agreement, we will acquire 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 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.

We estimate that cash due from VAALCO at closing will be in the range of approximately $30 to $40 million.

The acquisition is expected to close in the second quarter of 2024, with timing dependent upon receipt of all necessary regulatory approvals.

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

Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block.

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The amounts paid will be reimbursed through the Cost Account and are non-refundable.

In November 2021, a new abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($47.8 million, net to VAALCO) on an undiscounted basis.

The new abandonment estimate has been presented to the Gabonese Directorate of Hydrocarbons as required by the PSC.

In August 2023 , a new abandonment study was completed and such study estimated abandonment costs of approximately $77.9 million ($45.9 million, net to VAALCO) on an undiscounted basis.

The new abandonment estimate was presented to the Gabonese Directorate of Hydrocarbons as required by the PSC.

In the first quarter of 2023, the Directorate of Hydrocarbons in Gabon approved a $26.6 million ($15.6 million, net to VAALCO) abandonment funding payment associated with the FPSO retirement.

The Company received payment of $15.6 million in March 2023.

No activity was noted in the abandonment funding account during the remaining three quarters of the year.

No additional activity was noted in the abandonment funding account during the remainder of 2023 and in 2024.

At December 31, 2024, the balance of the abandonment fund w as $10.7 million ($ 6.3 millio n, net to VAALCO) on an undiscounted basis.

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This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets.

The Company is working with the Directorate of Hydrocarbons in Gabon to establish a payment schedule to resume funding of the abandonment fund.

Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments.

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

Capital Projects - In December 2024, Vaalco secured a rig for the 2025/26 drilling campaign at Etame.

Vaalco is currently finalizing locations and planning for the next drilling campaign, which is expected to commence in Q3 2025.

We currently have a 10 to 15 well drilling campaign in Egypt, where we have completed the drilling of two wells.

In Canada, we continue to drill, recomplete and workover wells adding to our production base and cash flows.

Leases - We are a party to several operating and financing lease arrangements, including operating leases, which may include corporate offices, drilling rigs, rental of marine vessels and helicopter, warehouse and storage facilities, equipment and financing lease agreements for the FSO, and equipment and vehicles used in operations.

The annual costs of these leases are significant to us.

For further information see Note 14 to our consolidated financial statements.

Merged Concession Agreement - 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.

For further information see Part IV, Item 15., Note 14.

Leases to our Consolidated Financial Statements.

Merged Concession Agreement - On January 20, 2022, prior to the consummation of the TransGlobe Acquisition, TransGlobe announced a fully executed Merged Concession Agreement with EGPC that merged the three existing Eastern Desert concessions with a 15-year primary term and improved economics.

In advance of the Minister of Petroleum and Mineral Resources of the Arab Republic of Egypt (the “Minister”) executing the Merged Concession Agreement, TransGlobe paid the first modernization payment of $15.0 million and signing bonus of $1.0 million as part of the conditions precedent to the official signing ceremony on January 19, 2022.

On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million.

In accordance with the Merged Concession Agreement, we agreed to substitute the 2023 and 2024 payments and issue two $10.0 million credits against receivables owed from EGPC.

We will make two further annual equalization payments of $10.0 million each beginning February 1, 2025 until February 1, 2026.

In accordance with the Merged Concession Agreement, we agreed to substitute the 2023, 2024 and 2025 payments and issue three $10.0 million credits against receivables owed from EGPC.

We plan to make the final annual equalization payment of $10.0 million on or before February 1, 2026.

We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the “Merged Concession Effective Date”).

As of December 31, 2024, the $50.0 million of financial work commitments had been delivered to EGPC.

FSO Agreements – On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement with World Carrier to replace the existing FPSO with an FSO unit at the Etame Marin block offshore Gabon.

FSO Agreements – On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement (the “Bareboat Charter”) with World Carrier to replace the existing FPSO with an FSO unit at the Etame Marin block offshore Gabon.

Pursuant to the Bareboat Charter, World Carrier will provide use of the Teli vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions.

Pursuant to the Operating Agreement, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO.

As consideration for the performance by World Carrier of the Operator Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Operating Agreement) until the end of the term, with such term being the same as the term in the Bareboat Charter.

Pursuant to the Bareboat Charter, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO.

As consideration for the performance by World Carrier of the Operator

Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Bareboat Charter) until the end of the term, with such term being the same as the term in the Bareboat Charter.

On October 19, 2022, we issued final acceptance certificate of the FSO.

On December 4, 2022, the first lifting from the FSO was successfully completed at the same time the final remaining volumes from the FPSO were removed.

BWE Consortium – On October 11, 2021, we announced our entry into a consortium with BW Energy and Panoro Energy and that 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 next step is concluding the terms of the PSC with the Gabonese government.

BW Energy will be the operator with a 37.5% working interest.

We will have a 37.5% working interest and Panoro Energy will have a 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.

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

It ceased hydrocarbon production as scheduled on January 31, 2025 and the final lifting of crude oil from the FPSO concluded on February 6, 2025.

The project team mobilization efforts are on schedule and have significantly progressed, deploying the necessary workforce support vessels and equipment to facilitate the safe disconnection of the FPSO.

The vessel is planned to be wet towed to the shipyards in Dubai for refurbishment upon departure from the field around March 2025.

BWE Consortium – We are a member of the BWE Consortium with BW Energy and Panoro Energy, which was awarded the two blocks in the 12th Offshore Licensing Round in Gabon.

The BWE Consortium and the Gabonese government came to an agreement on the commercial terms in February 2024.

All parties to the BWE Consortium signed the PSC with the Gabonese Government during the fourth quarter of 2024.

Pursuant to the terms of the PSC, BW Energy will be the operator with a 37.5% working interest, and VAALCO will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners.

The two blocks, Niosi Marin Block (previously G12-13) and the Guduma Marin Block (previously H12-13), are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

The two blocks, held by the BWE Consortium and the PSCs over the blocks, are currently under negotiation with the Gabonese government.

Dividend Policy – On February 14, 2023, we announced that our board of directors adopted of a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 2023 and continued throughout the year.

Dividend Policy – On February 14, 2023, we announced that our Board of Directors adopted a quarterly cash dividend policy of an expected $0.0625 per common share per quarter, which commenced in the first quarter of 2023 and continued throughout 2024.

Payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.

Share Buyback Program – On November 1, 2022, the Company announced that the Company’s board of directors formally ratified and approved a share buyback program.

The board of directors also directed management to implement a Rule 10b5-1 trading plan (the “10b5-1 Plan”) to facilitate share purchases through open market purchases, privately negotiated transactions, or otherwise in compliance with Rule 10b-18 under the Securities Exchange Act of 1934.

The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over a maximum period of up to 20 months.

Payment for shares repurchased under the share buyback program will be funded using the Company's cash on hand and cash flow from operations.

As of December 31, 2023, approximately $5.5 million remained available for repurchase under current authorizations.

Trends and Uncertainties

Geopolitical Conflict and Other Market Forces – The outbreak of armed conflict between Russia and Ukraine in February 2022 and the subsequent sanctions imposed on the Russian Federation has, and may continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets.

The ongoing conflict has caused, and could continue to intensify, volatility in oil and natural gas prices, and the extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

For example, shortly after the outbreak of the conflict through the year ended December 31, 2023 and on-going into 2024, we noticed that the lead times associated with obtaining materials to support our operations and drilling activities has lengthened, leading to delays and, in most cases, prices for materials have increased.

Management believes the ongoing war between Russia and Ukraine, the Houthis attacks on maritime vessels in the Red Sea region, conflicts in the Middle East and the related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy.

Geopolitical Conflict and Other Market Forces – Global conflicts, including Russia’s invasion of Ukraine, conflicts in the Middle East, and heightened tensions in the Pacific region, have significantly elevated global geopolitical tensions and security concerns.

Economic sanctions, export controls, and other trade restrictions, for instance those that the U.S.

Government and other nations implemented against Russia in light of its invasion of Ukraine or those relating to the conflict in the Middle East, could directly and indirectly continue to have, a destabilizing effect on the European continent and the global oil and natural gas markets.

The extended war between Russia and Ukraine and increasing hostilities in the Middle East, could continue to intensify and may cause prolonged uncertainty and volatility in commodity prices.

The extent and duration of the military action, sanctions and resulting market disruptions could be significant and could potentially have a substantial negative impact on the global economy and/or our business for an unknown period of time.

In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.

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Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+.

However, the Company has not received any mandate to reduce its current oil production from the Etame Marin block as a result of the OPEC+ initiatives.

ESG and Climate Change Effects – Sustainability matters continue to attract considerable public, regulatory and scientific attention.

In particular, we expect continued required reporting attention on climate change issues and emissions of greenhouse gases (“GHG”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion) and freshwater use.

In particular, we expect continued required reporting attention on climate change issues and emissions of GHG, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion) and freshwater use.

For example, in March 2024, the SEC adopted final rules under SEC Release No.

The Enhancement and Standardization of Climate-Related Disclosures for Investors, which requires registrants to provide certain climate-related information in their registration statements and annual reports.

The rules require information about a registrant’s climate-related risks that are reasonably likely to have a material impact on its business, results of operations, or financial condition.

These requirements are effective for the Company in various fiscal years, starting with its fiscal year beginning November 1, 2026.

On April 4, 2024, the SEC determined to voluntarily stay the final rules pending certain legal

The Company believes that the impact of these final rules on its consolidated financial statements and disclosures are not material.

This increased attention to climate change and environmental conservation coupled with stepped up government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against us.

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Our plans will enable us to monitor and improve matters related to ESG and climate change going forward.

For the past three years the Company has matured its reporting in line with the recommendations of the Task force on Climate-related Financial Disclosures (“TCFD”), which is recognized as the global standard in climate-related reporting.

The full TCFD report was included within the 2023 ESG Report (rather than in this Annual Report on Form 10-K or in the annual report which was published in connection with the annual meeting), as the ESG Report details with environmental, social and governance matters which the TCFD report forms an important part of the 2023 Sustainability Report is available on the Company's website.

In summary the Company considers itself aligned with both the Governance and Strategy pillars and the recommendations therein.

It does not consider itself aligned with Risk Management nor Metrics and Targets, but has made meaningful progress against certain of the underlying recommendations and provides statements of intent to address these recommendations during 2024.

For further detail see the table below.

Describe the Board’s oversight of climate-related risks and opportunities

The Board is actively engaged in understanding the climate-related risks relevant to the business.

Board supported establishment of decarbonization program and receives regular updates on progress.

At each board meeting, the Director of Global Sustainability & Regulatory Reporting reports emissions performance and progress within decarbonization program.

Management receives periodic updates from the ESG Engineer and outside consultants relating to climate-related matters.

The formalized management of climate-related matters, and specifically the Company's efforts to management its emissions profile, is delivered through its decarbonization working group and steering group, for identification of emissions reduction projects and subsequent approval respectively.

Describe management’s role in assessing and managing climate-related risks and opportunities.

The Company considers its approach to governance consistent with the recommendations.

Describe the climate-related risks and opportunities the organization has identified over the short, medium and long term.

The Company has identified transitional and physical risks and opportunities identified over the short (<2 years), medium (2 to 10 years) and long term (>10 years) within its Sustainability Report.

Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy, and financial planning.

The Company has indicated the potential impact of these risks and associated mitigations.

The Company continues to mature its approach to factoring in climate-related risks and opportunities into its strategy and financial planning.

This also includes its diligence through M&A activity.

Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenario

This year, the business conducted scenario analysis using the IEA’s Net Zero Emissions (NZE), Announced Pledges Scenario (APS) and Stated Policies Scenario (STEPS), the details and findings for which are enclosed in the Sustainability Report.

The Company considers its approach to Strategy consistent with the recommendations.

Risk Management

Describe the organization’s processes for identifying and assessing climate-related risks.

The Company has a defined risk management process for identifying and assessing risk, which incorporates climate-related risks.

Detail to this process can be found within the Sustainability Report and this Annual Report on Form 10-K.

Describe the organization’s processes for managing climate-related risks.

Whilst in development through the Decarbonization Program, the company considers its processes for managing climate-related risk to be inconsistent with the recommendations.

Describe how processes for identifying, assessing, and managing climate-related risks are integrated into the organization’s overall risk management.

During 2024, the Company will continue to conduct a review of its risk management processes, particularly in view of its enlarged portfolio.

Metrics and Targets

Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management process.

The Company reports its scope 1 and 2 emissions but has not yet set any targets.

In 2024, the Company expects to set and communicate its short-, mid-, and long-range emission targets.

Disclose Scope 1, Scope 2 and, if appropriate Scope 3 greenhouse gas (GHG) emissions and the related risks.

The Company considers its approach to metrics and targets for all aspects of its sustainability effort inconsistent with the recommendations and, through its decarbonization program, is seeking to set targets for its GHG emissions and other material topics in its sustainability efforts going forward.

Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targets

RESULTS OF OPERATIONS

Year Ended December 31, 2023 Compared to Year Ended December 31, 2022

We reported net income for the year ended December 31, 2023 of $60.4 m illion, compared to a net income of $51.9 million for the year ended December 31, 2022.

The year-over-year increase in earnings was mainly due to increases in sales volume partially offset by increased depreciation, depletion and amortization expense, production expenses and income taxes.

Further discussion of results by significant line item follows.

Twelve Months Ended December 31,

Increase/(Decrease)

(in thousands except per Boe information)

Net crude oil, natural gas, and NGLs sales volume (MBoe)

Average crude oil, natural gas and NGLs sales price (per Boe)

Net crude oil, natural gas, and NGLs revenue

Operating costs and expenses:

Production expense

FPSO demobilization and other costs

Exploration expense

Depreciation, depletion and amortization

General and administrative expense

Credit (recovery) losses and other

Total operating costs and expenses

Other operating income (expense), net

Operating income

The revenue changes between the years ended December 31, 2023 and 2022 identified as related to changes in price or volume are shown in the table below:

For the past four years the Company has matured its reporting in line with the recommendations of the Task force on Climate-related Financial Disclosures (“TCFD”), which is recognized as the global standard in climate-related reporting.

The full TCFD report was included within the 2023 Sustainability Report (rather than in this Annual Report on Form 10-K or in the annual report which was published in connection with the annual meeting), as the 2023 Sustainability Report details environmental, social and governance matters which the TCFD report forms an important part.

The 2023 Sustainability Report is available on the Company's website, which is not incorporated by reference hereto.

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

Year Ended December 31,

2024 2023 Increase (Decrease) in 2024 over 2023

(in thousands)

Total net revenue

(1) The price in the table above excludes revenues attributed to carried interests.

The table below shows net production, sales volumes and realized prices for both years.

Twelve Months Ended December 31,

Net crude oil, natural gas and NGLs production (MBoe)

Net crude oil, natural gas and NGLs sales (MBoe)

Average realized crude oil, natural gas and NGLs price ($/Boe)

Average Dated Brent spot price* ($/Bbl)

*Average of daily Dated Brent spot prices posted on the U.S.

Energy Information Administration website.

Crude oil, natural gas and NGLs net revenues increased $100.7 million, or approximately 28%, during the year ended December 31, 2023 compared to the same period of 2022.

This is due primarily to TransGlobe being included in revenues for only part of the fourth quarter of 2022.

Crude oil sales in Gabon are a function of the number and size of crude oil liftings in each year and thus crude oil sales do not always coincide with volumes produced in any given year.

The Company’s Gabon segment contributed $260.3 million of revenue to the Company’s total revenue during the year ended December 31, 2023.

This compares to the $306.8 million of revenue contributed by the Segment during the year ended December 31, 2022.

The total barrels lifted in Gabon for the year ended December 31, 2023 was less than the barrels lifted during the same period in 2022, mainly due to the timing of liftings.

In addition, the Gabon per barrel price received during the year ended December 31, 2023 was $22.90 less than the price received in 2022.

Our share of crude oil inventory, excluding royalty barrels, was approximately 68,766 and 76,274 barrels at December 31, 2023 and 2022, respectively.

Crude oil sales in Egypt are either sold to a third party via a cargo lifting or sold directly to the government, EGPC.

During the year ended December 31, 2023, the oil sold in Egypt was to a combination of Mercuria Energy and EGPC.

The Company’s Egypt segment contributed $161.0 million of revenue to the Company’s total revenue for the year ended December 31, 2023.

This compares to the $37.8 million of revenue contributed by the Segment during the year ended December 31, 2022.

The increase in revenues is due to the Company acquiring its Egypt segment in the fourth quarter of 2022.

At December 31, 2023, the Company’s Egypt segment had zero barrels in oil inventory.

Crude oil sales in Canada are normally sold through pipelines to a third party.

The Company’s Canadian segment contributed $34.4 million of revenue to the Company’s total revenue for the year ended December 31, 2023.

This compares to the $9.8 million of revenue contributed by the Segment during the year ended December 31, 2022.

The increase is due to the Company acquiring its Canadian segment in the fourth quarter of 2022.

Production expenses increased $40.5 million , or approximately 36%, in the year ended December 31, 2023 compared to the same period of 2022.

The increase in production expense was primarily driven by increased production and costs associated with the TransGlobe combination as well as higher Gabon costs due to the completed 2021/2022 drilling campaign.

During 2023, an unplanned maintenance issue resulted in our Gabon SENT gas line being down for a period of the year which resulted in increased diesel costs as the FSO required to be fueled by diesel rather than feed gas resulting in higher fuel costs.

VAALCO has also continued to see inflationary pressure on marine support vessels, our personnel and contractor costs.

On a per barrel basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 2023 decreased to $17.66 per barrel from $29.33 per barrel for the year ended December 31, 2022, primarily as a result of higher sales volumes.

For the twelve months ended December 31, 2023, we have not experienced any material operational disruptions associated with the COVID-19 pandemic.

For same period in 2022, we incurred $1.8 million, net to VAALCO, higher costs related to the proactive measures taken in response to the pandemic.

FPSO demobilization costs decreased $1.4 million, or approximately 16% , to $7.5 million in the year ended December 31, 2023 compared to the same period of 2022.

In 2023, it was determined that there was additional normally occurring radioactive material (NORMs) waste than anticipated connected to the FPSO from the Contractors' usage.

As such, VAALCO and JOA partners incurred an additional $7.5 million (net to VAALCO) in decommissioning fees, which was reported as a separate line item on the income statement.

These costs were incurred to retire the FPSO as we transitioned the Etame block to the FSO.

Exploration expen se s increased $1.7 mi llion or approximately 662%, in the year ended December 31, 2023 compared to the same period of 2022 due primarily to the abandonment of the Egyptian East Arta - 54 appraisal well and the abandonment of the NWG-5C1 appraisal well.

In 2022, exploration expense was not material to our results.

Depreciation, depletion and amortization increased $67.2 million, or approximately 139%, in the year ended December 31, 2023 compared to the same period of 2022.

The increase in depreciation, depletion and amortization expense is due to higher depletable costs associated with the FSO, the field reconfiguration capital costs at Etame and fair value of the acquired TransGlobe assets.

In addition, capital expenditures on new wells were brought online in 2023 for both Egypt and Canada, which also increased depreciation, depletion and amortization expense.

General and administrative expenses increased $13.8 million, or approximately 137% in the year ended December 31, 2023 compared to $10.1 million in the same period of 2022.

The increase in general and administrative expenses is primarily due to professional fees, accounting and legal services, and salaries and wages.

Credit loss and other allowances - Credit loss and other expense decreased $8.0 million, or approximately 259% in the year ended December 31, 2023 compared to the same period of 2022 We adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”) on January 1, 2023.

In connection with the adoption of ASU 2016-13, we established an opening balance sheet adjustment related to a receivable from a state sponsored oil refinery where we delivered oil pursuant to the domestic market needs obligation under the Etame PSC.

During the year ended December 31, 2023, the decrease in credit loss and other allowances was primarily due to two credit loss and other allowance reversals in 2023.

First, the Sogara receivable credit loss and other allowance was reversed for $3.1 million and second, the TVA receivable credit loss and other allowance was reversed for $7.6 million.

These reversals were offset by a credit loss and other allowance adjustment in Egypt of $5.2 million.

Other operating income (expense), net had no significant change from the prior year.

Derivative instruments gain (loss), net is attributable to our commodity instruments as discussed in Note 10 to the consolidated financial statements.

Derivative losses decreased $38.0 million to a gain of $0.2 million for the year ended December 31, 2023 from a loss of $37.8 million for the year ended December 31, 2022.

Derivative gains (losses) for the year ended December 31, 2023, are a result of the increase in the price of Dated Brent crude oil over the initial strike price per barrel of the option over the year ended December 31, 2022.

The same increase in price occurred, but to a lesser extent, in 2023.

During 2022, we changed our approach and the type of derivative instruments from swaps to costless collars.

Our derivative instruments currently cover a portion of our production through June 2024.

Interest (expense) income, net increased $4.4 million to an expense of $6.5 million for the year ended December 31, 2023 from expense of $2.0 million during the same period in 2022.

The increase of net interest expense for the year ended December 31, 2023, primarily results from our finance lease relating to the FSO but also includes commitments fees incurred on the Facility, amortization of debt issue costs related to the Facility and interest associated with our other finance leases partially offset by interest income.

Other (expense) income, net decreased $5.8 million to an expense of $2.3 million for the year ended December 31, 2023 from an expense of $8.0 million for the year ended December 31, 2022.

Other (expense) income, net normally consists of foreign currency losses as discussed in Note 2 to the consolidated financial statements.

However, for the year ended December 31, 2022, other (expense) income, net, also included $14.6 million of transaction costs associated with the Arrangement with TransGlobe, $2.7 million of foreign exchange losses associated with the TransGlobe activity from October 13, through December 31, 2022 partially offset by a bargain purchase gain of $9.7 million associated with the acquisition of TransGlobe.

Income tax expense (benefit) f or the year ended December 31, 2023 was an expense of $89.7 million.

This is comprised of $92.6 million of current tax provision and a deferred tax benefit of $2.9 million.

Income tax expense for the year ended December 31, 2022 was an expense of $71.4 million.

This is comprised of $26.6 million of current tax provision and a deferred tax provision of $44.8 million.

The current tax provision in both periods is primarily attributable to our operations in Gabon, Egypt and Canada.

The income tax expense is higher in 2023 than income tax for the comparable 2022 period as a result of higher revenues.

See Note 8 to the Consolidated Financial Statements for further discussion.

Net cash provided by operating activities before changes in operating assets and liabilities $ 184,312 $ 182,730 $ 1,582

Net change in operating assets and liabilities (70,594) 40,867 (111,461)

Net cash provided by (used in) operating activities 113,718 223,597 (109,879)

Net cash provided by (used in) investing activities (102,119) (97,223) (4,896)

Net cash provided by (used in) in financing activities (43,048) (56,819) 13,771

Effects of exchange rate changes on cash (3) (153) 150

Net change in cash, cash equivalents and restricted cash $ (31,452) $ 69,402 $ (100,854)

The $109.9 million decrease in net cash provided by operating activities during the year ended December 31, 2024 compared to the year ended December 31, 2023, was driven primarily by changes in operating assets and liabilities during the period.

The net decrease in changes provided by operating assets and liabilities of $111.5 million for the year ended December 31, 2024 compared to the same period of 2023 was related to a decrease in cash provided by trade receivable, Accounts with joint venture owners, net and Egypt receivables and other, net (collectively $86.1 million).

In addition, cash used by operating assets and liabilities increased due to a decrease in the accrued liabilities and other balances of $27.0 million.

Partially offsetting these changes was an increase in cash provided on a decrease in cash used in Accounts Payable of $14.9 million.

The $4.9 million increase in net cash used in investing activities during the year ended December 31, 2024 was due to the increase in cash capital spending in 2024.

In 2023 we incurred significant capital for the 2021/2022 Etame drilling campaign and the Etame field reconfiguration.

In 2024 capital spending was primarily attributable to the costs associated with the recompletion and drilling program.

In addition, VAALCO used $40.2 million in cash for the acquisition of

Svenska which is offset by the cash received from Svenska in the amount of $41.0 million.

See Part IV, Item 15., Note 4.

Acquisitions to the Consolidated Financial Statements for further discussion of the acquisition.

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

For the twelve months ended December 31, 2023, cash used in financing activities included $26.8 million for dividend distributions, $23.6 million for treasury stock repurchased under our stock repurchase plan, and $7.2 million of principal payments on our finance leases partially offset by $0.7 million in proceeds from options exercised.

Regulatory and Joint Interest Audits

See Part IV, Item 15., Note 12.

Commitment and Contingencies to the Consolidated Financial Statements for further discussion.

CRITICAL ACCOUNTING ESTIMATES

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In those cases, our reported results of operations would be different should we employ an alternative accounting method.

See Note 2 to the Consolidated Financial Statements for our accounting policy elections.

See Part IV, Item 15., Note 2.

Summary of Significant Accounting Policies to the Consolidated Financial Statements for our accounting policy elections.

Asset Retirement Obligations

The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations.

Estimating the future plugging and abandonment costs requires management to make estimates and judgments inherent in the present value calculation of the future obligation.

These include ultimate plugging and abandonment costs, inflation factors, credit adjusted discount rates, and timing of settlement and changes in the legal, regulatory, environmental and political environments.

We account for asset retirement obligations as required by ASC 410 — Asset Retirement and Environmental Obligations.

Under these standards, the fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made.

If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, the liability is recognized when a reasonable estimate of fair value can be made.

If a tangible long‑lived asset with an existing asset retirement obligation is acquired, a liability for that obligation is recognized at the asset’s acquisition or in service date.

In addition, a liability for the fair value of a conditional asset retirement obligation is recorded if the fair value of the liability can be reasonably estimated.

We capitalize the asset retirement costs by increasing the carrying amount of the related long‑lived asset by the same amount as the liability.

We record increases in the discounted abandonment liability resulting from the passage of time in depletion, depreciation and amortization in the consolidated statement of operations.

To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate.

The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits.

Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year.

Changes in tax laws, regulations, agreements and tax treaties or our level

of operations or profitability in each jurisdiction would impact our tax liability in any given year.

We also operate in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities.

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Should our expectations change regarding the expected future tax consequences, we may be required to record additional deferred taxes that could have a material effect on our consolidated financial position and results of operations.

For further discussion, see Note 8 to the Consolidated Financial Statements.

For further discussion, see Part IV, Item 15., Note 8.

Income Taxes to the Consolidated Financial Statements.

Oil and Gas Accounting Reserves Determination

13 unchanged sentences

as prescribed by the Society of Petroleum Engineers.

Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI for Gabon and Egypt, while GLJ evaluates our Canadian reserves.

Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI for Gabon, Egypt and Cote d'Ivoire, while GLJ evaluates our Canadian reserves.

Equatorial Guinea will receive a Management Case Report.

Our Board of Directors has established the Technical and Reserves (“T&R”) Committee with the authority, responsibility and primary purpose of assisting the board of directors in its oversight responsibilities relating to evaluating and reporting on oil and gas reserves.

The T&R Committee, to the extent it deems necessary or appropriate, will oversee (i) annual review of oil and gas reserves, (ii) procedures for evaluating and reporting oil and gas producing activities, and (iii) compliance with applicable regulatory and securities laws relating to the preparation and disclosure of information with respect to oil and gas reserves and shall consult with the Audit Committee on such matters relating to oil and gas reserves which impact our financial statements.

Our Board of Directors has established the Technical & Reserves Committee with the authority, responsibility and primary purpose of assisting the board of directors in its oversight responsibilities relating to evaluating and reporting on oil and gas reserves.

The Technical & Reserves Committee, to the extent it deems necessary or appropriate, will oversee (i) annual review of oil and gas reserves, (ii) procedures for evaluating and reporting oil and gas producing activities, and (iii) compliance with applicable regulatory and securities laws relating to the preparation and disclosure of information with

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

Our senior executives and reserve engineers oversee the preparation of our crude oil, natural gas and NGLs reserves and related disclosures by our appointed independent reserve engineers.

The T&R Committee and senior executives meet with the reserve engineers periodically to review the reserves process and results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between us and the independent reserve engineers.

The Technical & Reserves Committee and senior management meet with the reserve engineers periodically to review the reserves process and results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between us and the independent reserve engineers.

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

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The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows.

The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

For further discussion, see Note 9 to the Consolidated Financial Statements.

The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared reserve reports evaluated by independent reserve engineers adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

For further discussion, see Part IV, Item 15., Note 9.

Crude Oil, Natural Gas and NGLs Properties and Equipment, net to the Consolidated Financial Statements.

Impairment of Unproved Property

2 unchanged sentences

Unproved property costs consist mainly of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and to Block P in Equatorial Guinea.

In connection with the TransGlobe acquisition as discussed under Note 4 to the Consolidated Financial Statements, reserves in Egypt and Canada were also attributed to undeveloped properties and leasehold costs.

In connection with the TransGlobe Acquisition as discussed under Part IV, Item 15., Note 4.

Acquisitions to the Consolidated Financial Statements, reserves in Egypt and Canada were also attributed to undeveloped properties and leasehold costs.

Business Combinations

3 unchanged sentences

The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil, natural gas and NGLs properties.

If sufficient market data is not available regarding the fair values of proved and unproved properties, estimates of the fair value of crude oil and gas reserves are prepared.

Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and development costs are used to estimate future net cash flows.

For estimated proved reserves, the future net cash flows are discounted using a market-based discount rate determined appropriate at the time of the acquisition.

If sufficient market data is not available regarding the fair values of proved and unproved

properties, estimates of the fair value of crude oil and gas reserves are prepared.

Estimates of future prices to apply to the estimated reserves quantities acquired and estimates of future operating and capital costs are used to estimate future net cash flows.

For estimated proved reserves, the future net cash flows are discounted using a market-based discount rate and risk adjustment factors determined appropriate at the time of the acquisition.

Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

1 unchanged sentence

ACCOUNTING STANDARDS

See Note 3 to the Consolidated Financial Statements.

See Part IV, Item 15., Note 3.

New Accounting Standards to the Consolidated Financial Statements.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 5. Market for Registrant’s Common Equity