VAALCO ENERGY INC /DE/ (EGY)

Item 7. 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 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 2023 Form 10-K, which was filed with the SEC on March 15, 2024. Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” for further details about these statements.

INTRODUCTION

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

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

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

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

Recent Developments and Outlook

2024 Acquisition

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

Capital Program

We expect our 2025 capital program to range between $270 million to $330 million, assuming normal operating conditions, that prioritizes free cash flow generation and meaningful return of capital to shareholders. The program includes estimated spending of approximately between $115 million to $135 million for Gabon, $30 million to $40 million for Egypt, $8 million to $13 million for Canada, $1 million to $3 million for Equatorial Guinea, $115 million to $135 million for Cote d'Ivoire for oil and natural gas development and $1 million related to corporate and other capital costs. The foregoing amounts related to Etame projects in Gabon do not include amounts funded by the non-operating partners. See further discussion below under “Capital Resources, Liquidity and Cash Requirements” for further discussion on the capital spending for each of our operating segments.

Commodity Prices

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

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RESULTS OF OPERATIONS

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

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

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

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

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

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

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

Gabon

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

Egypt

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

Canada

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

Cote d'Ivoire

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

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

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

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

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

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

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

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

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

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

Other (expense) income, net increased $4.9 million to an expense of $5.8 million for the year ended December 31, 2024 from an expense of $0.9 million for the year ended December 31, 2023. Other (expense) income, net normally consists of foreign currency losses as discussed in Part IV, Item 15., Note 2. Summary of Significant Accounting Policies to the Consolidated Financial Statements. However, for the year ended December 31, 2024, other (expense) income, net, also included $3.9 million of transaction costs associated with the Svenska Acquisition.

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

CAPITAL RESOURCES AND LIQUIDITY

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Capital Expenditures

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

Recent Operational Updates

Gabon

The Company secured a drilling rig in December 2024 in conjunction with its 2025/2026 drilling program, which is planned to begin in mid-2025 to drill multiple development wells, and appraisal or exploration wells, as well as to perform workovers, with options to drill additional wells. We are planning on multiple wells in both the Etame field and at our SEENT platform, and a re-drill and several workovers in the Ebouri field to access production and reserves that were previously shut in and removed from proved reserves due to the presence of hydrogen sulfide.

Egypt

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

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

Cote d'Ivoire

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

Canada

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

Commodity Price Hedging

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

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

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

Cash on Hand

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

Capital Resources, Liquidity and Cash Requirements

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

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

Merged Concession Agreement

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

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RBL Facility Agreement and Available Credit

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

Cash Requirements

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

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

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

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

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

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

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

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

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

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

Trends and Uncertainties

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

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

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

For example, in March 2024, the SEC adopted final rules under SEC Release No. 33-11275: The Enhancement and Standardization of Climate-Related Disclosures for Investors, which requires registrants to provide certain climate-related information in their registration statements and annual reports. The rules require information about a registrant’s climate-related risks that are reasonably likely to have a material impact on its business, results of operations, or financial condition. These requirements are effective for the Company in various fiscal years, starting with its fiscal year beginning November 1, 2026. On April 4, 2024, the SEC determined to voluntarily stay the final rules pending certain legal

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

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

Cash Flows

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

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

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

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

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

Regulatory and Joint Interest Audits

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

CRITICAL ACCOUNTING ESTIMATES

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

Asset Retirement Obligations

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

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

Income Taxes

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

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

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

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

Oil and Gas Accounting Reserves Determination

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

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

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

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

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

•assumed effects of regulation by governmental agencies; and

•future development and operating costs.

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

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

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

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

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

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

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

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

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

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

Impairment of crude oil, natural gas and NGLs producing properties

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

Impairment of Unproved Property

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

Business Combinations

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

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

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

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

ACCOUNTING STANDARDS

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

Item 7. 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. 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 2022 as compared with 2021, 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. Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” for further details about these statements.

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INTRODUCTION

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

Gabon

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.

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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.

Egypt

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:

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Canada

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:

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

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

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.

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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.

Commodity Price Hedging

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

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

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

Cash on Hand

At December 31, 2023 and 2022, we had unrestricted cash of $121.0 million and $37.2 million, respectively. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

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.

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Capital Resources, Liquidity and Cash Requirements

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

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances 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. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends for other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

Merged Concession Agreement

For information on the Merged Concession Agreement, see Note 12 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.

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.

Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In 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 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. At December 31, 2023, the balance of the abandonment fund was $10.7 million ($6.3 million, net to VAALCO) on an undiscounted basis. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. 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. 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. 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. We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date"). As of December 31, 2023, the $50 million of financial work commitments had been delivered to EGPC.

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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. 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. 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 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. 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. 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. 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.

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

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil and natural gas prices, a decrease in demand for crude oil, natural gas or NGLs and future production cuts by OPEC+. 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. This increased attention to climate change and environmental conservation coupled with stepped up government incentives around renewable energy sources may result in demand shifts away from crude oil and natural gas products, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG reporting requirements, including establishing and communicating short and long-term goals and targets, furthering the reduction of our carbon footprint and measurement of GHG emissions. Sustainability remains an important topic to us, and we are in the process of developing a multi-year plan to establish and document our progress in achieving goals we set for ourselves across all areas of sustainability.  Our plans will enable us to monitor and improve matters related to ESG and climate change going forward.

For the past 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.

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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 million, 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.

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:

(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.

*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.

Gabon

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

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Egypt

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.

Canada

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 expensesincreased $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 expenses increased $1.7 million 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.

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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) for 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.

CRITICAL ACCOUNTING ESTIMATES

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

Income Taxes

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. When it is estimated to be more-likely-than-not that all or some portion of the deferred tax assets will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered include earnings generated in previous periods, forecasted earnings, the expiration period of carryovers, and overall economic conditions of the industry. As of December 31, 2023, we had deferred tax assets of $120.9 million primarily attributable to Canada, Gabon and U.S. basis differences in fixed assets, foreign tax credit carryforwards, and foreign net operating loss carryforwards. A valuation allowance of $83.9 million has been established against the deferred tax assets as of December 31, 2023, as management has concluded that it was more-likely-than-not that only some portion of the deferred tax assets would be realized. In future periods, we may determine that it is more-likely-than-not that all or some portion of the deferred tax assets will be realized, and in such period all or a portion of this valuation allowance may be reversed as the evidence warrants.

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

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Oil and Gas Accounting Reserves Determination

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

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

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

Management is responsible for estimating the quantities of proved crude oil, natural gas and NGLs reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the U.S. as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI for Gabon and Egypt, 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 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.

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

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

Impairment of crude oil, natural gas and NGLs producing properties

We review the crude oil, natural gas and NGLs producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared 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.

Impairment of Unproved Property

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

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Business Combinations

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

In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil, natural gas and NGLs properties. If sufficient market data is not available regarding the fair values of proved and unproved 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. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

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

ACCOUNTING STANDARDS

See Note 3 to the Consolidated Financial Statements.

Item 7. 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. 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 2021 as compared with 2020, refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2021 Form 10-K, which was filed with the SEC on March 11, 2022. Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” for further details about these statements.

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INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and NGLs. As operator, we have production operations and conduct exploration activities in Gabon, West Africa, Egypt and Canada. We also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. 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”". As discussed further in Note 4 to the Financial Statements, we have discontinued operations associated with our activities in Angola, West Africa and Yemen.

Our primary source of revenue historically has been from 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. The award is subject to concluding the terms of PSCs with the Gabonese government. BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners. The two blocks, G12-13 and H12-13 are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

On October 13, 2022, VAALCO and VAALCO Energy Canada ULC (“AcquireCo”), an indirect wholly-owned subsidiary, completed the previously announced business combination involving TransGlobe Energy Corporation (“TransGlobe”), whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares pursuant to a plan of arrangement (the “Arrangement”) and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO in accordance with the terms of an arrangement agreement entered into by VAALCO, AcquireCo and TransGlobe on July 13, 2022 (the “Arrangement Agreement”). Prior to the Arrangement, TransGlobe was a cash flow-focused oil and gas exploration and development company whose activities were concentrated in Egypt and Canada. The post-Arrangement company (the “Combined Company”) is an African-focused operator with a diverse portfolio of assets in Gabon, Egypt, Equatorial Guinea and Canada. See Note 4 to the consolidated financial statements for further discussion regarding the Arrangement.

RECENT DEVELOPMENTS

Share Buyback Program

On November 1, 2022, VAALCO announced that its board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement 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 Exchange Act. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using cash on hand and cash flow from operations.

The actual timing number and value of shares repurchased under the share buyback program will depend on a number of factors, including constraints specified in the Plan, VAALCO's stock price, general business and market conditions, and alternative investment opportunities. Under the Plan, our third-party broker, subject to SEC regulations regarding certain price, market, volume and timing constraints, has authority to purchase VAALCO common stock in accordance with the terms of the Plan.

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TransGlobe Arrangement

On October 13, 2022, VAALCO and AcquireCo completed the previously announced business combination with TransGlobe whereby AcquireCo acquired all of the issued and outstanding TransGlobe common shares pursuant to the Arrangement and TransGlobe became a direct wholly-owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of VAALCO, pursuant to the Arrangement Agreement.

Additionally, prior to the effective time of the Arrangement, TransGlobe repaid outstanding obligations and liabilities owned under TransGlobe’s credit facility with ATB Financial, representing approximately C$4.1 million. On December 19, 2022, TransGlobe, as an indirect wholly-owned subsidiary of VAALCO, voluntarily delivered a notice of termination to ATB Financial relating to the ATB Facility. As of December 31, 2022, no amounts were drawn on the revolving loan facility. On January 5, 2023, the ATB Facility was formally closed.

For the twelve months ended December 31, 2022, included in the line item "Other (expense) income, net" is $14.6 million of transactions costs associated with the Arrangement with TransGlobe.

Entry into a Facility Agreement

On May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”), a wholly owned subsidiary of VAALCO, entered into a facility agreement (the “Facility Agreement”) by and among VAALCO, VAALCO Gabon and, together with VAALCO, the “Guarantors”), Glencore Energy UK Ltd., as mandated lead arranger, technical bank and facility agent (“Glencore”), the Law Debenture Trust Corporation P.L.C., as security agent, and the other financial institutions named therein (the “Lenders”), providing for a senior secured reserve-based revolving credit facility (the “Facility”) in an aggregate maximum principal amount of up to $50.0 million. Subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million (any such increase, an “Additional Commitment”). Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million. See “—Capital Resources and Liquidity – RBL Facility Agreement” for more information regarding the Facility.

Marine Construction Agreement for Subsea Reconfiguration

On March 17, 2022, VAALCO Gabon, a wholly owned subsidiary of VAALCO, entered into the Marine Construction Agreement with DOF Subsea, to support the subsea reconfiguration in connection with the replacement of the then-existing FPSO vessel with a FSO vessel at the Etame Marin field offshore Gabon. Pursuant to the Marine Construction Agreement, DOF Subsea agreed to, among other things, provide all personnel, crew and equipment necessary to assist in the reconfiguration of the Etame field subsea infrastructure to accommodate all field production to the flow to the FSO, which conversion included (i) assistance with retrieval of over 5,000 meters of new flexible pipelines from a manufacturing facility in the United Kingdom, transporting the pipelines to Gabon and installing the pipelines in the Etame field, (ii) performing the retrieval and relocation of existing in-field flowlines and umbilicals to accommodate the reconfigured field development plan and (iii) assistance in the connection of new risers to the FSO. Pursuant to the Marine Construction Agreement, DOF Subsea provided an offshore construction vessel to facilitate the performance of the Services. In October 2022, we completed the FSO installation and field reconfiguration at Etame field.

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Recent Operational Updates

NYSE Noncompliance Notice

On April 3, 2023, the Company was notified by the New York Stock Exchange (the “NYSE”) that it was not in compliance with the NYSE’s continued listing requirements under the timely filing criteria established in Section 802.01E of the NYSE Listed Company Manual as a result of its failure to timely file its Annual Report on Form 10-K for the fiscal year ended December 31, 2022. By filing this report, the Company believes it has remedied its non-compliance.

Gabon Operations Update

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).

2021/2022 Drilling Campaign

In conjunction with the 2021/2022 drilling program, that began in December 2021, we executed a contract with Borr Jack-Up XIV Inc., an affiliate of Borr Drilling Limited, to drill a minimum of three wells with options to drill additional wells. In December 2021, we spudded the Etame 8H-ST, the first well of the 2021/2022 drilling program. In February 2022 we completed the drilling of the Etame 8H-ST well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST development well, which targeted the Gamba reservoir. The Etame 8H-ST demonstrated an initial flow rate of approximately 5,000 gross barrels of oil per day BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. The 8H-ST was shut in due to Hydrogen sulfide that arose during the drilling process, but a side track was performed to rectify this and resume production. In April 2022, the Avouma 3H-ST well was completed and brought online with an initial production rate of approximately 3,100 gross BOPD, 1,589 BOPD net to VAALCO’s 58.8% working interest in 2022.

In July 2022 we completed the South Tchibala 1HB-ST well on the Avouma platform, targeting the Gamba reservoir and also testing the Dentale formation. The section of the Gamba sand encountered was not economically viable to complete in this wellbore. However, we did discover two potential zones, the Dentale D1 and Dentale D9 zones for development. The well was completed in the Dentale D1 formation and brought online in July with an initial production rate of approximately 293-390 gross BOPD, 150-200 BOPD net to VAALCO’s 58.8% working interest in 2022. The Dentale D9 well is temporarily shut-in, however; we plan to evaluate and recomplete the D9 zone during the next drilling campaign.

Following the completion of the South Tchibala 1HB-ST well, the rig was mobilized to the Southeast Etame North Tchibala Platform to drill the North Tchibala 2H-ST (“ETBNM 2H-ST”) well, targeting the Dentale formation, which is productive in this area of the Etame license. This mobilization was delayed by two weeks due to weather and the rig began operations on the well in late July. After setting up the equipment and completing operations to re-enter the well, VAALCO began drilling the North Tchibala 2H-ST well on August 8, 2022. The North Tchibala 2H-ST well was brought online in early November and flowed at a low, controlled rate to allow for cleanup and to minimize negative impact to the completion. Through end of January 2023, the well flowed, with temporary interruptions for operational activity and shut-ins for pressure build up analysis. During this time, the well produced approximately 18,500 gross barrels of oil, or about 250 gross bopd and recovered about 36% of injected completion fluid. Cleanup is continuing and pressure transient analysis indicates that both completed zones may be contributing. The well is naturally flowing with no water production and stable reservoir pressure indicating minimal depletion.

Following the drilling campaign, we utilized the rig to perform a workover on the North Tchibala 1H (“ETBNM 1H”) well due to a safety valve in the well that required replacement. With the rig already on site it was easier and more economic to utilize the rig to complete the workover following the completion of the North Tchibala 2H-ST well. The final well operation performed by the rig was another workover, the Southeast Etame 4-H (“ETSEM-4H”) well, which restored production to between 1,000 and 1,500 gross BOPD upon completion, following the well going offline in early September as a result of an upper ESP failure and we were unable to restart the upper ESP or the lower ESP to restore production. Utilizing the rig for the workovers has optimized the total cost of the 2021/2022 drilling campaign at Etame.

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After the execution of the workovers the drilling rig was released on November 17, 2022.

We estimate the cost of the current 2021/2022 drilling program with four wells and two workovers to be $180 million, or $114 million, net to VAALCO’s participating interest. For 2022, we incurred approximately $148 million, or about $94 million net to VAALCO’s participating interest.

Acquisition of Additional Working Interest at Etame Marin Block

In November 2020, we signed a SPA to acquire Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon. On February 25, 2021, we completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, we owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased our working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired have been included in our results for periods after February 25, 2021. All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil, natural gas and NGLs properties, asset retirement obligations and working capital items were recorded at their fair value. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, a $7.7 million bargain purchase gain was recognized. A bargain purchase gain of $5.2 million is included in “Other (expense) income, net” under “Other income (expense)” in the consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2021. An income tax benefit of $2.5 million, related to the bargain purchase gain, is also included in the consolidated statements of operations and comprehensive income (loss). The reason for the bargain purchase gain is mainly due to the lower crude oil price outlook used when the SPA was signed, November 17, 2020, and the higher oil price outlook on February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

Under the terms of the SPA, a contingent payment of $5.0 million was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1, 2020 to June 30, 2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the contingent payment were met and on April 29, 2021, we paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.

The actual impact of the Sasol Acquisition for the year ended December 31, 2022 and 2021 was an increase to “Crude oil, natural gas and NGLs sales” in the consolidated statements of operations and other comprehensive income (loss) of $144.8 million and $84.6 million, respectively, and a $14.6 million and $29.3 million increase to “Net income”, respectively, in the consolidated statements of operations and other comprehensive income (loss).

Egypt Operations Update

We continued to use the EDC-64 rig in its Eastern Desert drilling campaign. During the quarter, we drilled and cased two development wells and drilled two exploration wells. A third development well, the Arta-77Hz, as discussed below, was brought online in the first quarter of 2023.

The M-17 well was drilled to a total depth of 1,900 meters targeting Asl reservoirs in the M Field. The well was fully logged and evaluated. The Asl-A reservoir has an internally estimated 11.5 meters of net oil pay, 12.2 m of net oil pay in the Asl-B reservoir and 1.1 m of net oil pay in the Asl-D reservoir. The Asl-A reservoir was perforated and put on production with a current rate of 348 BOPD at a 42% water cut (heavy crude, field estimate) (Initial production over 30 days was 406 BOPD at a 23% water cut).

The NWG-2INJ-1A well was drilled to a total depth of 1,318 meters targeting the Nukhul reservoir. Initially intended as a water injector, the well encountered strong oil and gas shows in the Nukhul. The well was fully logged and evaluated with an internally estimated 6.4 meters of net oil pay in the Nukhul. This well was put on production with a current rate of 122 BOPD (heavy crude, field estimate) at 40% water cut.

Two exploration wells were drilled in the north of the Petrobakr concession. Both wells targeted the Red Bed reservoir trend that successfully produces at the NWG-38 Field in this area. NWG-44A was drilled to a depth of 1,737 meters and NWG-46X was drilled to a depth of 1,463 meters. Both wells encountered minor oil and gas shows in the Red Bed formation, however the zone was tight. Both wells were plugged and abandoned as they were dry.

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Late in the fourth quarter of 2022, we initiated the Arta horizontal pilot program in the Arta Field by successfully drilling the Arta-77Hz well targeting the Nukhul reservoir. The well was drilled to a total depth of 2,409 meters MD (1,182 meters TVD). The lateral was successfully drilled through the Nukhul reservoir encountering 1,363 meters of reservoir with good oil and gas shows. Subsequent to the quarter, the well was completed through the lateral section with a 14-stage cemented frac sleeve liner. The well was multi-stage stimulated and put on production in the first quarter of 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 2023 to resume production.

Canada Operations Update

In Canada, TransGlobe planned a seven horizontal Cardium reservoir wells (four 2-mile, and three 1-mile) drilling campaign in the South Harmattan area during 2022. Four of those wells were brought on production in the third quarter prior to the acquisition agreement and one well was brought on production in the fourth quarter of 2022 and the remaining two wells were brought on production during the first quarter of 2023.

The 4-10-29-3W5 well drilled in July 2022 and was completed and brought on production in late December 2022. As of the first quarter of 2023, the well is currently producing at a field estimated rate of 100 BOPD. The 4-18-29-3W5 and 4-24-29-4W5 wells were completed in the fourth quarter of 2022 and brought on production in the first quarter of 2023.

The 2023 drilling campaign commenced in January 2023 with the drilling of 12-12-30-4W5, spud on January 28, 2023. The well was drilled to a total depth of 6,713 meters. The second well of the program, 16-30-29-3W5, spud on February 22, 2023, and is currently being drilled.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the years ended December 31, 2022 and 2021 are as follows:

The $65.0 million increase in net cash provided by our operating activities before changes in operating assets and liabilities for the year ended December 31, 2022 compared to the same period of 2021 was due to higher pricing, more production and the increased number of producing wells partially offset by negative changes due to higher realized losses on derivatives. The net increase in changes provided by operating assets and liabilities of $13.7 million for the year ended December 31, 2022 compared to the same period of 2021 was primarily related to increases in accounts payable partially offset by changes in prepayments and other assets and crude oil inventory and other changes.

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The $84.1 million increase in net cash used in investing activities during the twelve months ended December 31, 2022 was due to increases in cash capital spending in 2022 for items to related to the 2021/2022 drilling campaign and the Etame field reconfiguration of $146.4 million, $13.5 million of cash used in the Egypt and Canadian operations for property and equipment partially offset by $36.7 million of cash acquired in the TransGlobe acquisition. For the twelve months ended December 31, 2021, net cash used in investing activities was due to cash of $22.5 million used in the purchase of Sasol’s interest in the Etame Block and $16.6 million for property and equipment on a cash basis.

Net cash used in financing activities during the year ended December 31, 2022 included $9.4 million dividends paid to common shareholders, $3.8 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, $2.1 million in deferred financing costs and $3.0 million related to principal finance lease payments, partially offset by $0.3 million in proceeds from options exercised. For the year ended December 31, 2021, net cash used in financing activities included $1.4 million for treasury stock as a result of tax withholding on options exercised and vested restricted stock as discussed in Note 17 to our consolidated financial statements, partially offset by $1.3 million in proceeds from options exercised.

Capital Expenditures

In February 2020, we fully complied with the capital and other commitments associated with the 2018 PSC Extension.

During 2022, we had accrual basis expenditures attributable to continuing operations of $434.4 million, that includes $162.4 million for Gabon, $168.0 million for Egypt, $103.3 million for Canada and $0.7 million for the corporate offices, compared to $79.2 million for 2021. 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. Capital expenditures in 2021 were attributable to expenditures related to the 2021/2022 drilling program and the Sasol acquisition. See table below in “Capital Resources, Liquidity and Cash Requirements” for further information.

Regulatory and Joint Interest Audits

We are subject to periodic routine audits by various government agencies in Gabon, 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.

Commodity Price Hedging

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

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

The following are the hedges outstanding at December 31, 2022:

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The following additional hedges were entered into in 2023:

Cash on Hand

At December 31, 2022, we had unrestricted cash of $37.2 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

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.

In the period of October 14 through December 31, 2022, all sales in Egypt were to EGPC. Sales to EGPC are normally settled two to four weeks from delivery.

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.

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

Capital Resources, Liquidity and Cash Requirements

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

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances 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. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or pay dividends for other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

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Merged Concession Agreement

On January 19, 2022, legacy subsidiaries of TransGlobe executed the Merged Concession Agreement with EGPC to update and merge TransGlobe’s three Egyptian concessions in West Bakr, West Gharib and NW Gharib (the “Merged Concession”). The modernization payments under the Merged Concession Agreement total $65.0 million and are payable over six years from the Merged Concession Effective Date. Under the Merged Concession Agreement, we will be required to pay an additional $10.0 million on February 1 for each of the next three years. In addition, we have committed to spending a minimum of $50.0 million over each five-year period for the 15 years of the primary term (totaling $150.0 million). Our ability to make scheduled payments arising from the Merged Concession Agreement will depend on our financial condition and operating performance, which is subject to then prevailing economic, industry and competitive conditions and to certain financial, business, legislative, regulatory and other factors beyond our control.

RBL Facility Agreement and Available Credit

On May 16, 2022, VAALCO Gabon (Etame), Inc. entered into Facility Agreement by and among VAALCO, VAALCO Gabon, Glencore, the Law Debenture Trust Corporation P.L.C. and the Lenders, providing for a senior secured reserve-based revolving credit facility in an aggregate maximum principal amount of up to $50.0 million (the “Initial Total Commitment”). In addition, subject to certain conditions, the Borrower may agree with any Lender or other bank or financial institution to increase the total commitments available under the Facility by an aggregate amount not to exceed $50.0 million. Beginning October 1, 2023 and thereafter on April 1 and October 1 of each year during the term of the Facility, the Initial Total Commitment, as increased by any Additional Commitment, will be reduced by $6.25 million.

The Facility provides for determination of the borrowing base asset based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is determined and re-determined by the Lenders on March 31 and September 30 of each year. Based on the redetermination performed during the year, there was no change in the borrowing base.

The Borrower’s obligations under the Facility Agreement are guaranteed by Guarantors and secured by interests, rights, activities, assets, entitlements, and development in the Etame Marin Permit (Block G64-160) Field and any other assets which are approved by the Majority Lenders (as defined in the Facility Agreement).

Each loan under the Facility will bear interest at a rate equal to LIBOR plus a margin (the “Applicable Margin”) of (i) 6.00% until the third anniversary of the Facility Agreement or (ii) 6.25% from the third anniversary of the Facility Agreement until the Final Maturity Date (defined below).

Pursuant to the Facility Agreement, we shall pay to Glencore for the account of each Lender a quarterly commitment fee equal to (i) 35% per annum of the Applicable Margin on the daily amount by which the lower of the total commitments and the borrowing base amount exceeds the amount of all outstanding utilizations under the Facility, plus (ii) 20% per annum of the Applicable Margin on the daily amount by which the total commitments exceed the borrowing base amount. The Borrower is also required to pay customary arrangement and security agent fees.

The Facility Agreement contains certain debt covenants, including that, as of the last day of each calendar quarter, (i) the ratio of Consolidated Total Net Debt to EBITDAX (as each term is defined in the Facility Agreement) for the trailing 12 months shall not exceed 3.0x and (ii) consolidated cash and cash equivalents shall not be lower than $10.0 million. As of December 31, 2022, our borrowing base was $50.0 million. The amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Facility Agreement. We were in compliance with all debt covenants at December 31, 2022. As of December 31, 2022, we had no outstanding borrowings under the facility. With regard to the requirement that we deliver our fiscal year 2022 annual financial statements to Glencore within 90 days of the end of each fiscal year, we have requested and received an extension until April 17, 2023.

The Facility will mature on the earlier of (i) the fifth anniversary of the date on which all conditions precedent to the first utilization of the Facility have been satisfied and (ii) the Reserve Tail Date (as defined in the Facility Agreement) (the “Final Maturity Date”).

In connection with the Arrangement with TransGlobe in October 2022, prior to the effective time of the Arrangement, TransGlobe repaid in full all outstanding obligations and liabilities owed under TransGlobe’s credit facility with ATB Financial, representing approximately C$4.1 million. On December 19, 2022, TransGlobe, as an indirect wholly-owned subsidiary of VAALCO, voluntarily delivered a notice of termination to ATB Financial relating to the ATB Facility. As of December 31, 2022, no amounts were drawn on the revolving loan facility. On January 5, 2023, the ATB Facility was formally closed. Termination of the ATB Facility did not affect our $50.0 million senior secured reserve-based revolving credit facility with Glencore.

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Cash Requirements

Our material cash requirements generally consist of finance leases, operating leases, purchase obligations, capital projects and 3D seismic processing, the Sasol Acquisition, 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.

Sasol Acquisition – As a result of completing the Sasol Acquisition on February 25, 2021, our obligations with respect to development activities in the Etame have increased based on the increase in our working interest in the Etame from 31.1 % at December 31, 2020, to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired in the Sasol Acquisition have been included in VAALCO’s results for periods after February 25, 2021. We expect that part of this increase will be offset by an increase in our operating cash flows based on our increased portion of the Etame production.

Abandonment Funding - Under the terms of the Etame PSC, we have a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the applicable abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In 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. Through December 31, 2022, $35.0 million ($20.6 million, net to VAALCO) on an undiscounted basis has been funded. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the consolidated balance sheets. 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 helicopters, warehouse and storage facilities, equipment and financing lease agreements for the FSO and generators used in the operations of the Etame Marin block and for equipment, offices and vehicles used in the operations of Canada and Egypt. 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. On February 1, 2022, TransGlobe paid the second modernization payment of $10.0 million. In accordance with the Merged Concession, we agreed to substitute the 2023 payment and issue a $10.0 million credit against receivables owed from EGPC. We will make three further annual equalization payments of $10.0 million each beginning February 1, 2024, until February 1, 2026. We also have minimum financial work commitments of $50.0 million per each five-year period of the primary development term, commencing on February 1, 2020 (the "Merged Concession Effective Date"). As of December 31, 2022, the $50 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 a 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.

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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) in 2022 of which $6 million will be recovered against future rentals. In addition, VAALCO Gabon agreed to pay a daily hire rate at certain rates specified therein, with such hire rate being based on the year within the term.

In connection with the implementation of the FSO, we were required to incur certain Etame field configuration expenses in order to facilitate the FSO. 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 Gabon).

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. The award is subject to 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. The two blocks will be held by the BWE Consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by an additional two more years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.

Drilling Program – We commenced the 2021/2022 drilling campaign in December 2021 with the drilling of the Etame 8H-ST development well. In February 2022 we completed the drilling of the Etame 8H-ST well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST development well, which targeted the Gamba reservoir. The initial flow rate of the ETAME 8H-ST well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. The 8H-ST was shut in due to Hydrogen sulfide that arose during the drilling process, but a side track was performed to rectify this and resume production. In April 2022, the Avouma 3H-ST well was completed and brought online with an initial production rate of approximately 3,100 gross BOPD, 1,589 BOPD net to VAALCO’s 58.8% working interest in 2022.

In July 2022 we completed the South Tchibala 1HB-ST well on the Avouma platform, targeting the Gamba reservoir and also testing the Dentale formation. The section of the Gamba sand encountered was not economically viable to complete in this wellbore. However, we did discover two potential zones, the Dentale D1 and Dentale D9 zones for development. The well was completed in the Dentale D1 formation and brought online in July with an initial production rate of approximately 293-390 gross BOPD, 150-200 BOPD net to VAALCO’s 58.8% working interest in 2022. The Dentale D9 well is temporarily shut-in, however; we plan to evaluate and recomplete the D9 zone during the next drilling campaign.

Following the completion of the South Tchibala 1HB-ST well, the rig was mobilized to the Southeast Etame North Tchibala Platform to drill the North Tchibala 2H-ST well, targeting the Dentale formation, which is productive in this area of the Etame license. This mobilization was delayed by two weeks due to weather and the rig began operations on the well in late July. After setting up the equipment and completing operations to re-enter the well, VAALCO began drilling the North Tchibala 2H-ST well on August 8, 2022. The North Tchibala 2H-ST well was brought online in early November and flowed at a low, controlled rate to allow for cleanup and to minimize negative impact to the completion. Through end of January, the well flowed, with temporary interruptions for operational activity and shut-ins for pressure build up analysis. During this time, the well produced approximately 18,500 gross barrels of oil, or about 250 gross BOPD and recovered about 36% of injected completion fluid. Cleanup is continuing and pressure transient analysis indicates that both completed zones may be contributing. The well is naturally flowing with no water production and stable reservoir pressure indicating minimal depletion.

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We recently utilized the rig to perform a workover on the North Tchibala 1H well due to a safety valve in the well that required replacement. With the rig already on site it was easier and more economic to utilize the rig to complete the workover following the completion of the North Tchibala 2H-ST well. The final well operation planned for the rig was another workover, the South East Etame 4-H well, which restored production to 1,000 and 1,500 gross BOPD upon completion. This well went offline in early September as a result of an upper ESP failure and we were unable to restart the upper ESP or the lower ESP to restore production. Utilizing the rig for the workovers has optimized the total cost of the 2021/2022 drilling campaign at Etame.

After the execution of the workovers the drilling rig was released on November 17, 2022.

We estimate the cost of the current 2021/2022 drilling program with four wells and two workovers to be $180 million, or $114 million, net to VAALCO’s participating interest. For 2022, we incurred approximately $148 million, or about $94 million net to VAALCO’s participating interest.

TransGlobe Acquisition – On October 13, 2022, the Company and AcquireCo completed the business combination with TransGlobe. At the effective time of the Arrangement and pursuant to the Arrangement Agreement, each common share of TransGlobe issued and outstanding immediately prior to the effective time of the Arrangement was converted into the right to receive 0.6727 of a share of VAALCO common stock. The total number of VAALCO shares issued to TransGlobe’s shareholders was approximately 49.3 million. In addition, we incurred $14.6 million of transaction costs associated with the acquisition agreement.

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, commencing in the first quarter of 2023. 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.

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, we announced that our board of directors formally ratified and approved the share buyback program that was announced on August 8, 2022 in conjunction with our business combination with TransGlobe. The board of directors also directed management to implement 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 Exchange Act. The 10b5-1 Plan provides for an aggregate purchase of currently outstanding common stock up to $30 million over 20 months. Payment for shares repurchased under the share buyback program will be funded using our cash on hand and cash flow from operations. As of December 31, 2022, approximately $27.0 million remained available for repurchase under current authorizations.

Trends and Uncertainties

COVID-19 Pandemic – While crude oil prices have recently been at the highest levels seen in recent years, the continued spread of COVID-19, including vaccine-resistant strains, or deterioration in crude oil, natural gas and NGLs prices could result in additional adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 may have on our ability to continue to conduct our operations.

Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

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War with Ukraine 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.

Further, the slowdown in the Chinese economy is negatively impacting the global market and the global supply chain problems may have a material adverse impact on our financial results and business operations, including our timing and ability to complete future drilling campaigns and other efforts required to advance the development of our crude oil, natural gas and NGLs properties.

For example, shortly after the outbreak of the conflict through the year ended December 31, 2022 and on-going into 2023, 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 and its related impact on the global economy are causing supply chain issues and energy concerns in parts of the global economy. In addition, increased inflation, higher interest rates and current turmoil in certain governments are impacting the global supply chain market.

Commodity Prices – Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGLs prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil prices, a decrease in demand for crude oil and future production cuts by OPEC+. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts by September 2022. However, as a result of the recent decline in oil prices, on October 5, 2022, OPEC+ announced plans to reduce overall oil production by 2 MMBbls per day starting November 2022. To date, we have not received any mandate to reduce our current oil production from the Etame Marin block as a result of the OPEC+ initiative. Brent crude prices were approximately $82.82 per barrel as of December 31, 2022.

ESG and Climate Change Effects – ESG matters continue to attract considerable public and scientific attention. In particular, we expect continued regulatory attention on climate change issues and emissions of GHGs, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil, natural gas and NGLs combustion). This increased attention to climate change and environmental conservation may result in demand shifts away from crude oil, natural gas and NGLs products to alternative forms of energy, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investors’ investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG standards, including the reduction of our carbon footprint and measurement of GHG emissions. ESG is important to us, and we are in the process of developing a multi-year plan to establish and document our ESG base currently and developing a systematic plan to monitor and improve matters related to ESG and climate change going forward. Additional ESG regulation will result in additional expenses and may result in less revenue due to the cost of compliance.

VAALCO recognizes climate change as a risk to the business and industry.

It also recognizes the potential for the business to decarbonize its operations, reduce operating costs, and deliver more sustainably produced oil and gas products, whilst serving its developing host nation that still require improved energy access and supply, and the economic benefits the industry generates, directly and indirectly.

The Company acknowledges the requirement to share information with stakeholders regarding its response to climate-related risks and opportunities.

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 will be included within the 2022 ESG Report (rather than in this Annual Report on Form 10-K or in the annual report which will be 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 2022 ESG Report will be made available on the Company's website.

In summary the Company considers itself consistent with both the Governance and Strategy pillars and the recommendations therein. It does not consider itself consistent 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 2023. For further detail see the table below.

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Hedging

We seek to mitigate the impact of volatility in crude oil prices through hedging.

The following are the hedges outstanding at December 31, 2022:

The following are the additional hedges entered into in 2023:

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RESULTS OF OPERATIONS

Year Ended December 31, 2022 Compared to Year Ended December 31, 2021

We reported net income for the year ended December 31, 2022 of $51.9 million, compared to a net income of $81.8 million for the year ended December 31, 2021. The year-over-year decrease in earnings was mainly due to increases in depreciation, depletion and amortization expense, production expenses and changes in taxes from a benefit in 2021 to an expense in 2022. Further discussion of results by significant line item follows.

The revenue changes between the years ended December 31, 2022 and 2021 identified as related to changes in price or volume are shown in the table below:

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

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

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

Crude oil, natural gas and NGL revenues increased $155.3 million, or approximately 78.0%, during the year ended December 31, 2022 compared to the same period of 2021. The total barrels lifted in Gabon for the year ended December 31, 2022 was more than the barrels lifted during the same period in 2021, mainly due to 2021/2022 drilling campaign partially offset by natural declines in production. In addition, the per barrel price received during 2022 was $32.43 higher than the price received in 2021. 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. We made 11 liftings in Gabon during both years ended December 31, 2022, and December 31, 2021, respectively. Our share of crude oil inventory, excluding royalty barrels, was approximately 76,274 and 75,680 barrels at December 31, 2022 and 2021, respectively. Crude oil, natural gas and NGLs sales also increased due to the TransGlobe acquisition on October 13, 2022 with sales from both Egypt and Canada being recorded from the acquisition date through December 31. 2022 and contributing $47.6 million of revenue in 2022.

Production expenses increased $31.4 million, or approximately 38.7%, in the year ended December 31, 2022 compared to the same period of 2021. $17.5 million of the increase is attributable to our Gabon operations with higher marine fuel and personnel costs as a result of inflation increases. In addition, we incurred $13.9 million of production expense related to our Egypt and Canadian operations from the date of the acquisition through December 31, 2022. On a per barrel NRI basis, production expense, excluding workover expense and stock compensation expense, for the year ended December 31, 2022, increased to $29.33 per barrel from $26.77 per barrel for the year ended December 31, 2021, primarily as a result of higher marine, fuel and personnel costs. While we have not experienced any significant operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $1.8 million of COVID-19 related costs, net to VAALCO, for the year ended December 31, 2022. For the same period in 2021, we incurred $2.9 million, net to VAALCO, higher costs related to the proactive measures taken in response to the pandemic.

FPSO demobilization costs for the year ended December 31, 2022 were $8.9 million. These costs were incurred to retire the FPSO as we transitioned the Etame block to the FSO. No similar expenses were incurred during the same period in 2021.

Exploration expenses decreased $1.3 million or approximately 83.7%, in the year ended December 31, 2022 compared to the same period of 2021. The decrease is due to incurring minimal amounts for seismic processing costs for the year ended December 31, 2022 compared to the same period in 2021 when we were processing the seismic data acquired in 2020.

Depreciation, depletion and amortization increased $27.1 million, or approximately 128.6%, in the year ended December 31, 2022 compared to the same period of 2021. $13.7 million of the change is attributable to our Gabon operations while $13.4 million of the change is due to the depletions associated with the TransGlobe acquisition from the date of acquisition, October 13, 2022, through December 31, 2022. The higher depletion associated with the Gabon operations is due to higher depletable costs associated with the 2021/2022 drilling campaign.

General and administrative expenses decreased $4.7 million, or approximately 31.8% in the year ended December 31, 2022 compared to $14.8 million in the same period of 2021. The decrease in expense was primarily related to lower corporate salary and wages, lower legal fees, lower compensation related to liability awards and higher allocations of corporate expenses in 2022 (collectively $10.2 million) partially offset by higher audit and professional fees, higher stock based compensation related to equity awards and higher professional fees and other fees (collectively $5.2 million). In addition, we incurred $0.4 million of general and administrative expenses associated with the TransGlobe acquisition from the acquisition date, October 13, 2022, through December 31, 2022

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Bad debt (recovery) expense and other reflected bad debt expense associated with the VAT allowance for the year ended December 31, 2022. Bad debt expense increased $2.2 million, or approximately 252.2% in the year ended December 31, 2022 compared to the same period of 2021 as a result of increased spending as a result of the 2021/2022 drilling campaign partially offset by $0.5 million, net to VAALCO, in VAT payments received.

Other operating income (expense), net increased $0.5 million, or approximately 108.6%, in the year ended December 31, 2022 compared to the same period of 2021. For the year ended December 31, 2021 other operating income (expense) is primarily comprised of the difference between the fair value of the contingent consideration paid to Sasol in April 2021 of $5.0 million, and the fair value of the contingent consideration on the closing date of the Sasol Acquisition of $4.6 million.

Derivative instruments gain (loss), net is attributable to our commodity instruments as discussed in Note 10 to the consolidated financial statements. Derivative losses increased $15.0 million to a loss of $37.8 million loss for the year ended December 31, 2022 from a loss of $22.8 million for the year ended December 31, 2021. We used swaps to hedge our production through the third quarter of 2022 and then transitioned to costless collars beginning in the fourth quarter of 2022. Every quarter in 2021 and continuing through the third quarter of 2022 Dated Brent crude oil prices increased. Since VAALCO owes the counterparty for any Dated Brent price over the initial per barrel value, we continued to incur losses associated our commodity swap derivatives. Our current commodity derivative instruments cover a portion of our production through June 2023.

Interest (expense) income, net increased $2.0 million to an expense of $2.0 million for the year ended December 31, 2022 from expense of $0.0 million during the same period in 2021. Net interest expense for the year ended December 31, 2022, includes commitment fees incurred on the Facility, amortization of debt issue costs related to the VAALCO RBL Facility and interest associated with our finance leases partially offset by interest income.

Other (expense) income, net decreased $11.5 million to expense of $8.0 million for the year ended December 31, 2022 from income of $3.5 million for the year ended December 31, 2021. 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 $10.8 million associated with the acquisition of TransGlobe. Other (expense) income, net, was primarily attributable to $5.2 million for the bargain purchase gain offset by $1.0 million for an acquisition success fee and foreign currency losses for the year ended December 31, 2021.

Income tax expense (benefit) 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. Income tax expense for the year ended December 31, 2021 was a benefit of $22.1 million. This is comprised of $42.4 million of deferred tax benefit and a current tax provision of $20.3 million. The current tax provision in both periods is primarily attributable to our operations in Gabon, Egypt and Canada and is higher in 2022 than income tax for the comparable 2021 period as a result of higher revenues. See Note 8 to the Consolidated Financial Statements for further discussion.

Income (loss) from discontinued operations, net of tax for the year ended December 31, 2022 was attributable to our Angola and Yemen segments as discussed further in Note 4 to the Financial Statements. For the year ended December 31, 2021, loss from discontinued operations was attributable to our Angola segment. The loss from discontinued operations for the year ended and December 31, 2022 and December 31, 2021, respectively, was related to Angola and Yemen administration costs.

CRITICAL ACCOUNTING ESTIMATES

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

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Income Taxes

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level of operations or profitability in each jurisdiction would impact our tax liability in any given year. We also operate in foreign jurisdictions where the tax laws relating to the crude oil, natural gas and NGLs industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. When it is estimated to be more-likely-than-not that all or some portion of the deferred tax assets will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered include earnings generated in previous periods, forecasted earnings, the expiration period of carryovers, and overall economic conditions of the industry. As of December 31, 2022, we had deferred tax assets of $99.6 million primarily attributable to Canada, Gabon and U.S. basis differences in fixed assets, foreign tax credit carryforwards, and U.S. and foreign net operating loss carryforwards. A valuation allowance of $47.6 million has been established against the deferred tax assets as of December 31, 2022, as management has concluded that it was more-likely-than-not that only some portion of the deferred tax assets would be realized. In future periods, we may determine that it is more-likely-than-not that all or some portion of the deferred tax assets will be realized, and in such period all or a portion of this valuation allowance may be reversed as the evidence warrants.

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

Oil and Gas Accounting Reserves Determination

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

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

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

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

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Table of Contents

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 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.

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

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

Impairment of crude oil, natural gas and NGLs producing properties

We review the crude oil, natural gas and NGLs producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil, natural gas and NGLs property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared 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.

Impairment of Unproved Property

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

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Table of Contents

Business Combinations

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

In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil, natural gas and NGLs properties. If sufficient market data is not available regarding the fair values of proved and unproved 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. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

We estimate the fair values of the acquired assets and assumed liabilities as of the date of the acquisition, and our estimates are subject to adjustment through completion, which is in each case within one year of the acquisition date, based on our ongoing assessments of the fair values of property and equipment, intangible assets, other assets and liabilities and our evaluation of tax positions and contingencies. See Note 4 to the Consolidated Financial Statements under “Acquisitions and dispositions” for further discussion.

NEW ACCOUNTING STANDARDS

See Note 3 to the Consolidated Financial Statements.

Item 7. 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. 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 2020 as compared with 2019, refer to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our 2020 Form 10-K, which was filed with the SEC on March 9, 2021. Certain statements in our discussion below are forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause actual results to differ materially from those implied or expressed by the

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forward-looking statements. Please see “Cautionary Statement Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” for further details about these statements.

INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration activities in Gabon, West Africa. We also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. For further discussion of our two operating segments see “Item 1. Business – Segment and Geographical Information – “Gabon Segment” and “Equatorial Guinea Segment”. As discussed further in Note 4 to the Financial Statements, we have discontinued operations associated with our activities in Angola, West Africa.

RECENT DEVELOPMENTS

On March 11, 2020, the World Health Organization classified the outbreak of a new strain of coronavirus (“COVID-19”) as a pandemic, based on the rapid increase in global exposure. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the oil and gas industry. The adverse economic effects of the COVID-19 outbreak materially decreased demand for crude oil based on the restrictions in place by governments trying to curb the outbreak and changes in consumer behavior. This led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices in 2020. In April 2020, countries within OPEC+, which includes Gabon, reached an agreement to cut crude oil production to reduce the gap between excess supply and demand, in an effort to stabilize the international oil market. Gabon has undertaken measures to comply with such OPEC+ production quota agreement and, as a result, the Minister of Hydrocarbons in Gabon requested that we reduce our production. In response to such request from the Minister of Hydrocarbons, beginning in July 2020 and continuing through April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. Reductions in production have significantly improved the demand/supply imbalance, and crude oil prices have improved from the lows seen in March and April of 2020. As a result, in July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. The decision to increase in production was reaffirmed by an OPEC+ meeting held on February 2, 2022. See “Liquidity” below for discussion of the unexpired commodity swaps we have in place.

We considered the impact of the COVID-19 pandemic and the substantial decline in crude oil prices on the assumptions and estimates used for preparation of the financial statements. As a result, we recognized a number of material charges during the three months ended March 31, 2020, including impairments to our capitalized costs for proved crude oil and natural gas properties and valuation allowances on its deferred tax assets. These are discussed further in the notes to our consolidated financial statements included in this report.

The spread of COVID-19, including vaccine-resistant strains, or repeated deterioration in crude oil and natural gas prices could result in future adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations. Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

In response to the COVID-19 outbreak and the current pricing environment, we took the following measures:

 put in place social distancing measures at our work sites;

 actively screened and monitored employees and contractors that come on to our facilities including testing and quarantines with onsite medical supervision;

 engaged in regular company-wide COVID-19 updates to keep employees informed of key developments; and

 implemented sharing certain costs, such as supply vessels, helicopter, and personnel with other operators in the region.

We expect to continue to take proactive steps to manage any disruption in our business caused by COVID-19 and to protect the health and safety of our employees. However, the health and safety measures we and our vendors have taken have resulted in us incurring higher costs. As a result of these factors and the conditions described above, 2020 was one of the most uncertain and disruptive years that the industry has ever seen.

For the year ended December 31, 2021, crude oil prices have improved, there were no disruptions to operations as a result of COVID-19 or any strain thereof, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, no additional charges or impairments were required for the twelve months ended December 31, 2021. Crude oil prices have continually increased and are currently at the highest levels seen in recent years. The average annual Brent price per barrel for the year ended December 31, 2020 was $41.96 and increased 69% to $70.86 for the year ended December 31, 2021. At the end of 2021 and continuing into 2022, travel-related restrictions have lessened, access to vaccines that reduce the spread and impact of COVID-19 and its variants have become more accessible and the global economy appears

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more flexible to continuing to effectively operate in a COVID-19 environment. However, while the business environment in 2021 improved, the COVID-19 situation and effects thereof remain fluid. A prolonged outbreak may have a material adverse impact on our financial results and business operations, including the timing and ability of us to complete future drilling campaigns and other efforts required to advance the development of our crude oil and natural gas properties.

Recent Operational Updates

Provisional Award of Two Offshore Blocks in Gabon

The BWE Consortium of VAALCO, BW Energy and Panoro Energy were provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of production sharing contracts (“PSCs”) with the Gabonese government. BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

Charter Agreement for the Floating Storage and Offloading Unit

We are currently a party to an FPSO charter for the storage of all of the crude oil that we produce. This contract will expire in September 2022. In August of 2021, we and our co-venturers at Etame approved the Bareboat Contract and Operating Agreement (collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. (“World Carrier”) to replace the existing FPSO with an FSO. The FSO Agreements require a prepayment of $2 million gross ($1.3 million net) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. Current total capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO).

In December 2020, we completed the acquisition of approximately 1,000 square kilometers of new dual-azimuth proprietary 3-D seismic data over the entire Etame Marin block and have now processed the new 3-D seismic which has allowed us to optimize drilling locations for the 2021/2022 drilling campaign. The seismic data enhanced sub-surface imaging by merging legacy data with newly acquired seismic allowing for the first continuous 3-D seismic over the entire block. In conjunction with the 2021/2022 drilling program, that began in December 2021, we executed a contract with Borr Jack-Up XIV Inc., an affiliate of Borr Drilling Limited, to drill a minimum of three wells with options to drill additional wells. On October 4, 2021, we novated the Borr Jack-Up XIV Inc contract with Borr West Africa Assets, Inc. In December of 2021, we spudded the Etame 8H sidetrack, the first well of the 2021/2022 drilling program. In February of 2022 we completed the drilling of the Etame 8-H well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST1 development well, which is targeting the Gamba reservoir. The initial flow rate of the ETAME 8-H well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022.

We estimate the range of cost of the 2021/2022 drilling program with four wells to be between $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest with about $26 million to about $31 million gross expected in 2021, or about $16 million to $20 million net to VAALCO.

Acquisition of Additional Working Interest at Etame Marin Block

In November 2020, we signed a SPA to acquire Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon. On February 25, 2021, we completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, we owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased our working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired have been included in our results for periods after February 25, 2021. All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items were recorded at their fair value. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed, a $7.7 million bargain purchase gain was recognized. A bargain purchase gain of $5.2 million is included in “Other, net” under “Other income (expense)” in the consolidated statements of operations. An income tax benefit of $2.5 million, related to the bargain purchase gain, is also included in the consolidated statements of operations. The reason for the bargain purchase gain is mainly due to the lower crude oil price outlook used when the SPA was signed, November 17, 2020, and the higher oil price outlook on February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

The actual impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $84.6 million for the year ended December 31, 2021and a $29.3 million increase to “Net income” in the condensed consolidated statement of operations. Under the terms of the SPA, a contingent payment of $5.0 million was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1, 2020 to June 30, 2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the

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contingent payment were met and on April 29, 2021, we paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.

Workovers

In October 2021, we completed two workovers on the Ebouri 2-H and the Etame 12-H wells. The workover on the Ebouri 2-H well increased production from about 500 gross barrels of oil per day (“BOPD“) (255 BOPD, net) prior to the workover to approximately 1,400 gross BOPD (715 BOPD, net). For the Etame 12-H well, we replaced both the upper and lower electrical submersible pumps (“ESP”) and reconfigured the ESP design resulting in restored production of about 1,800 gross BOPD (920 BOPD, net).

DISCONTINUED OPERATIONS-ANGOLA

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carried Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P. that we were withdrawing from the PSA. Further to our decision to withdraw from Angola, we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the Financial Statements for all periods presented. See Note 4 to the Financial Statements. In the first quarter of 2019, the Company and Sonangol E.P. entered into a settlement agreement finalizing the Company’s rights, liabilities and outstanding obligations for Block 5 in Angola. Pursuant to the settlement agreement, the Company agreed to pay $4.5 million to Angola National Agency of Petroleum, Gas, and Biofuels, as National Concessionaire, and to eliminate the $3.3 million receivable from Sonangol P&P. The receivable was related to joint interest billings and was reflected as current assets from discontinued operations at year-end 2018. As a result, the Company adjusted a previously accrued liability and recognized a net of tax non-cash benefit from discontinued operations of $5.7 million in the first quarter of 2019. In July 2019, subsequent to the publication of an executive decree from the Ministry of Mineral Resources and Petroleum, the Company paid the $4.5 million due under the settlement agreement. For the twelve months ended December 31, 2021 or December 31, 2020, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the years 2021 and 2020 are as follows:

The increase in net cash provided by our operating activities for the year ended December 31, 2021 compared to the same period of 2020 includes a $41.2 million increase in cash generated by continuing operations before change in operating assets and liabilities, which was mainly due to higher revenue as referenced below in Results of Operations. The decrease in cash resulting from the net change in operating assets and liabilities of $18.8 million for the year ended December 31, 2020 reflects an increase of $25.6 million in trade receivables and an increase of $11.1 million in other receivables partially offset by increases in foreign income taxes payable and accrued liabilities of $10.2 million.

Property and equipment expenditures have historically been our most significant use of cash in investing activities. Net cash used in investing activities during the year ended December 31, 2021 included $22.5 million paid for the completion of the Sasol Acquisition as discussed in Note 4 to our consolidated financial statements. In addition, we incurred on a cash basis $16.6 million for property and equipment primarily related to equipment and enhancements as well as expenditures related to the 2021/2022 drilling program as discussed in “Recent Operational Updates” above. See “— Capital Expenditures and Capital Resources, Liquidity, and Cash

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Requirements” below for further discussion. For 2020, the $20.0 million cash basis expenditures consisted of $19.7 million related to the 2019/2020 drilling program and $0.3 million paid for equipment and enhancements.

For the year ended December 31, 2021, net cash used in financing activities included $1.4 million for treasury stock as a result of tax withholding on options exercised and vested restricted stock as discussed in Note 16 to our condensed consolidated financial statements, partially offset by $1.3 million in proceeds from options exercised. Net cash used in financing activities during the year ended December 31, 2020 included $1.1 million for treasury stock purchases primarily made under the Company’s stock repurchase plan.

Capital Expenditures

At December 31, 2018, pursuant to the PSC Extension, we had commitments for capital expenditures related to the drilling of two wells and two appraisal wellbores by September 16, 2020. In February 2020, these commitments were fully met as a result of drilling the Etame 9P and SE Etame 4P appraisal wellbores in 2019 and 2020, respectively, as well as the completion of the Etame 9H and Etame 11H development wells in 2019 and 2020, respectively. See “— Capital Expenditures and Capital Resources, Liquidity, and Cash Requirements” below for further discussion.

During 2021, we had accrual basis capital expenditures attributable to continuing operations of $79.2 million, that includes the Sasol Acquisition, compared to $10.5 million accrual basis capital expenditures in 2020. 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 2021 are attributable to expenditures related to the 2021/2022 drilling program and Sasol acquisition and the 2020 capital expenditures were attributable to expenditures related to the 2019/2020 drilling program, a portion of seismic acquisition costs and equipment and enhancements. See table below in “Capital Resources, Liquidity and Cash Requirements” for further information.

Regulatory and Joint Interest Audits

We are subject to periodic routine audits by various government agencies in Gabon, 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 Financial Statements for further discussion.

Commodity Price Hedging

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

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

For the period from January to June 2019, we had commodity swap contracts for approximately 172,000 barrels of crude oil. On May 6, 2019, we entered into commodity swaps at a Dated Brent weighted average price of $66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. On January 22, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022 for a quantity of 709,262 barrels. On May 6, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels.

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The following are the hedges outstanding at December 31, 2021:

The following are the additional hedges entered into in 2022:

Cash on Hand

At December 31, 2021, we had unrestricted cash of $48.7 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

We currently sell our crude oil production from Gabon under a term contract that began in January 2020 and ends in July 2022. Pricing under this contract is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Capital Resources, Liquidity and Cash Requirements

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

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 to support our current cash requirements, including those related to our 2021/2022 drilling program and our ability to fund the FPSO through September 2022 and the FSO charter, through March 2023. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or other similar transactions depends on operating and economic conditions, some of which are beyond our control. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. We are continuing to evaluate all uses of cash, including opportunistic acquisitions, and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

Cash Requirements

Our material cash requirements generally consist of operating leases, purchase obligations, capital projects and 3D seismic processing, the Sasol Acquisition and abandonment funding, each of which is discussed in further detail below.

Sasol Acquisition – As a result of completing the Sasol Acquisition on February 25, 2021, our obligations with respect to development activities in the Etame have increased based on the increase in our working interest in the Etame from 31.1 % at December 31, 2020, to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Company’s Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired in the Sasol Acquisition have been included in VAALCO’s results for periods after February 25, 2021. We expect that part of this increase will be offset by an increase in our operating cash flows based on our increased portion of the Etame production.

FSO Agreements – We are currently a party to an FPSO charter for the production and storage of all of the crude oil that we produce. This contract will expire in September 2022. 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 a FSO unit at the Etame Marin block offshore Gabon. Pursuant to the Bareboat Charter, World Carrier will provide use of the Cap Diamant 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

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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.

The FSO Agreements require a prepayment of $2 million gross ($1.2 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. In addition, VAALCO Gabon agreed to pay a daily hire rate at certain rates specified therein, with such hire rate being based on the year within the term.

The aggregate amount to be paid to World Carrier under the FSO Agreements during 2022 is approximately $11 million gross (or $6.5 million net to VAALCO based on its participating interest in the Etame block), net of any applicable taxes.

In connection with the implementation of the FSO, we are required to incur certain capital expenses in order to facilitate the FSO. Current total capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO).

BWE Consortium – On October 11, 2021 we announced our entry into a consortium with BW Energy and Panoro Energy (the “BWE Consortium”) and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to 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. The two blocks will be held by the BWE Consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by a further two more years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.

Drilling Program – We commenced the 2021/2022 drilling campaign in December 2021 with the drilling of the Etame 8-H development well. In February of 2022 we completed the drilling of the Etame 8-H well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST1 development well, which is targeting the Gamba reservoir. The initial flow rate of the ETAME 8-H well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. We expect the campaign to include two development wells and two appraisal wells at an estimated cost of $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest.

In June 2021, in conjunction with our 2021/2022 drilling program, we entered into a contract with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells.

Trends and Uncertainties

Sasol Acquisition – At December 31, 2020, we had 3.2 MMBbls of estimated net proved reserves, all of which are related to the Etame Marin block offshore Gabon. In February 2021, as a result of the Sasol acquisition, we increased our working interest in the Etame Marin block from 31.1% to 58.8%. The current term for exploitation of the reserves in the Etame Marin block ends in September 2028 with rights for two five-year extension periods. Except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, our estimated net proved reserves will generally decline as reserves are produced. While both short-term and long-term liquidity are impacted by crude oil prices, our long-term liquidity also depends upon our ability to find, develop or acquire additional crude oil and natural gas reserves that are economically recoverable.

COVID-19 Pandemic – While crude oil prices are currently at the highest levels seen in recent years, the continued spread of COVID-19, including vaccine-resistant strains, or deterioration in crude oil and natural gas prices could result in additional adverse impacts on our results of operations, cash flows and financial position, including asset impairments. The health of our employees, contractors and vendors, and our ability to meet staffing needs in our operations and certain critical functions cannot be predicted and is vital to our operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations.

Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, and we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.

Commodity Prices – Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil prices, a decrease in demand for crude oil and future production cuts by OPEC+. In 2020, crude oil prices experienced a significant decline as a result of the substantial decline in the global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. Reductions in production have significantly improved the demand/supply imbalance and crude oil prices have improved from the lows

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seen in March and April of 2020. Between July 2020 and April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. Brent crude prices were approximately $77 per barrel as of December 31, 2021. The decision to increase in production was reaffirmed by an OPEC+ meeting held on February 2, 2022.

ESG and Climate Change Effects – ESG matters continue to attract considerable public and scientific attention. In particular, we expect continued regulatory attention on climate change issues and emissions of greenhouse gases (“GHGs”), including methane (a primary component of natural gas) and carbon dioxide (a byproduct of crude oil and natural gas combustion). This increased attention to climate change and environmental conservation may result in demand shifts away from crude oil and natural gas products to alternative forms of energy, higher regulatory and compliance costs, additional governmental investigations and private litigation against us. For example, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In addition, institutional investors, proxy advisory firms and other industry participants continue to focus on ESG matters, including climate change. We expect that this heightened focus will continue to drive ESG efforts across our industry and influence investors’ investment and voting decisions, which for some investors may lead to less favorable sentiment towards carbon assets and diversion of investment to other industries. Consistent with the increased attention on ESG matters and climate change, we have prioritized and are committed to responsible environmental practices by monitoring our adherence to ESG standards, including the reduction of our carbon footprint and measurement of GHG emissions. ESG is important to us, and we are in the process of developing a multi-year plan to establish and document our ESG base currently and developing a systematic plan to monitor and improve matters related to ESG and climate change going forward.

Hedging

We seek to mitigate the impact of volatility in crude oil prices through hedging On January 22, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022 for 709,262 barrels. On May 6, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, we entered commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels.

The following are the hedges outstanding at December 31, 2021:

The following are the additional hedges entered into in 2022:

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RESULTS OF OPERATIONS

Year Ended December 31, 2021 Compared to Year Ended December 31, 2020

We reported net income for the year ended December 31, 2021 of $81.8 million, compared to a net loss of $48.2 million for the year ended December 31, 2020. The year-over-year increase in earnings was mainly due to increases in sales volumes and prices received and no impairment and deferred tax valuation adjustments in 2021. Substantially all of our operations are attributable to our Gabon segment. Further discussion of results by significant line item follows.

The revenue changes between the years ended December 31, 2021 and 2020 identified as related to changes in price or volume are shown in the table below:

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

Crude oil revenues increased $131.9 million, or approximately 196.3%, during the year ended December 31, 2021 compared to the same period of 2020. The total barrels lifted for the year ended December 31, 2021 was more than the barrels lifted during the same period in 2020, mainly due to our increased working interest as a result of the Sasol Acquisition partially offset by natural declines in production. The Crude oil sales are a function of the number and size of crude oil liftings in each quarter and thus crude oil sales do not always coincide with volumes produced in any given quarter. We made 11 liftings during both years ended December 31, 2021 and December 31, 2020, respectively. Our share of crude oil inventory, excluding royalty barrels, was approximately 75,680 and 172,276 barrels at December 31, 2021 and 2020, respectively. The crude oil inventory was higher at December 31, 2020 due to the scheduled December 2020 lifting being delayed to January 2021.

Production expenses increased $43.9 million, or approximately 117.8%, in the year ended December 31, 2021 compared to the same period of 2020. The increase in expense was primarily related to costs as a result of our increased working interest as a result of the Sasol Acquisition, increased workover costs and higher marine and personnel costs. On a per barrel basis, production expense, excluding workover expense, for the year ended December 31, 2021 increased to $26.77 per barrel from $21.38 per barrel for the year ended December 31, 2020 primarily as a result of a natural decline in oil production and higher marine and personnel costs. While we have

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not experienced any significant operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $2.9 million, net to VAALCO, for the year ended December 2021 and $1.6 million, net to VAALCO, for the year ended December 2020, in higher costs related to the proactive measures taken in response to the pandemic.

Exploration expenses decreased $2.0 million or approximately 56.0%, in the year ended December 31, 2021 compared to the same period of 2020. The exploration expense in 2020 related to seismic acquisition costs while the expenses in 2021 were due to seismic processing costs. See further information at Item 1. Business – Segment and Geographic Information – Gabon Segment — Development.

Depreciation, depletion and amortization increased $11.7 million, or approximately 124.5%, in the year ended December 31, 2021 compared to the same period of 2020 due to higher depletable costs associated with the Sasol Acquisition. Partially offset by an increase in reserve base associated with the positive revisions in reserves.

Impairment of proved crude oil and natural gas properties for the year ended December 31, 2020 of $30.6 million was the result of declining forecasted crude oil prices primarily due to the COVID-19 pandemic. No impairment was recorded for the year ended December 31, 2021.

General and administrative expenses increased $4.1 million, or approximately 38.1% in the year ended December 31, 2021 compared to the same period of 2020. The increase in expense was in part related to a $2.3 million increase in stock-based compensation expense. The change in expense related to stock appreciation rights (“SARs”) expense was an increase of $2.1 million. SARs liability awards are fair valued. The primary driver to changes in the fair value of these awards is changes in the Company’s stock price. See Note 16 for further discussion. In addition, wages and salaries increased $1.1 million due to severance costs associated with changes in key personnel and legal fees increased $0.3 million due more legal activity in the current year.

Bad debt (recovery) expense and other reflected bad debt expense associated with the VAT allowance for the year ended December 31, 2021. Bad debt expense decreased $0.3 million, or approximately 24.9% in the year ended December 31, 2021 compared to the same period of 2020 mainly due to receipt of $0.5 million, net to VAALCO, in 2021 partially offset by increases in the allowance for bad debt.

Other operating income (expense), net decreased $1.2 million, or approximately 73.6%, in the year ended December 31, 2021 compared to the same period of 2020. The $0.4 million balance for the year ended December 31, 2021 is primarily comprised of the difference between the fair value of the contingent consideration paid to Sasol in April 2021, $5.0 million, and the fair value of the contingent consideration on the closing date of the Sasol Acquisition, $4.6 million. For the year ended December 31, 2020 other operating income (expense) is primarily related to a $0.8 million payment to resolve claims made by one of the Etame Marin block joint venture owners related to audits for the years 2017 and 2018 as well as $0.9 million in inventory obsolescence.

Derivative instruments gain (loss), net is attributable to our commodity swaps as discussed in Note 10 to the Financial Statements. The $22.8 million loss for the year ended December 31, 2021 is a result of the increase in the price of Dated Brent crude oil above the weighted average swap price of our derivative instruments during the year ended December 31, 2021 as compared to a decrease in the price of Dated Brent crude oil that resulted in a $6.6 million gain during the comparable period in 2020. Our derivative instruments currently cover a portion of our production through September 2022.

Interest income (expense), net for the years ended December 31, 2020 and 2019 relate to interest income on cash balances and are not material to the financial statements.

Other, net for the year ended December 31, 2021 is primarily attributable to $5.2 million for the bargain purchase gain offset by $1.0 million for an acquisition success fee and foreign currency losses. Other, net was not significant for the year ended December 31, 2020.

Income tax expense (benefit) for the year ended December 31, 2021 was $(22.1) million. This is comprised of $42.4 million of deferred tax benefit and a current tax provision of $20.3 million. The income tax expense for the year ended December 31, 2020 was $27.7 million. This is comprised of $ 24.2 million of deferred tax expense and a current tax provision of $3.5 million. The deferred income tax expense for the year ended December 31, 2020 included a $41.6 million charge to increase the valuation allowances on U.S. and Gabon deferred tax assets due to a decrease in future estimated taxable earnings primarily as a result of lower crude oil prices as well as the overall economic conditions of the industry. The current tax provision in both periods is primarily attributable to our operations in Gabon and is higher in 2021 than income tax for the comparable 2020 period as a result of higher revenues. See Note 8 to the Financial Statements for further discussion.

Income (loss) from discontinued operations, net of tax for the years ended December 31, 2021 and 2020 are attributable to our Angola segment as discussed further in Note 4 to the Financial Statements. The loss from discontinued operations for the year ended December 31, 2021 and December 31,2020, respectively, was related to Angola administration costs.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of Financial Statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the Financial Statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions on financial

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condition or operating performance is material. Actual results could differ from the estimates and assumptions used. Further, in some cases, GAAP allows more than one alternative accounting method for reporting. In those cases, our reported results of operations would be different should we employ an alternative accounting method. See Note 2 to the Financial Statements for our accounting policy elections.

Income Taxes

Our annual tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to us in the various jurisdictions in which we operate. The determination and evaluation of our annual tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which we operate and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or our level 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 and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While our income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized. When it is estimated to be more-likely-than-not that all or some portion of the deferred tax assets will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered include earnings generated in previous periods, forecasted earnings, the expiration period of carryovers, and overall economic conditions of the industry. As of December 31, 2021, the Company had deferred tax assets of $86.9 million primarily attributable to Gabon and U.S. federal taxes related to basis differences in fixed assets, foreign tax credit carryforwards, and U.S. and foreign net operating loss carryforwards. A valuation allowance of $46.9 million has been established against the deferred tax assets as of December 31, 2021, as management has concluded that it was more-likely-than-not that only some portion of the deferred tax assets would be realized. In future periods, we may determine that it is more-likely-than-not that all or some portion of the deferred tax assets will be realized, and in such period all or a portion of this valuation allowance may be reversed as the evidence warrants.

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

Oil and Gas Accounting Reserves Determination

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

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

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

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

future crude oil and natural gas quality differentials;

assumed effects of regulation by governmental agencies; and

future development and operating costs.

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

Management is responsible for estimating the quantities of proved crude oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the U.S. as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI.

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

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

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

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

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

See “Item 15. Exhibits and Financial Statement Schedules – Supplemental Information on Crude Oil and Natural Gas Producing Activities (unaudited).”

Successful Efforts Method of Accounting for Crude Oil and Natural Gas Activities

We use the successful efforts method to account for our crude oil and natural gas activities. Management believes that this method is preferable, as we have focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results. Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred.

The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability.

Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

We capitalize interest, if debt is outstanding, during drilling operations in our exploration and development activities.

We review the crude oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. Our assessment involves a high degree of estimation uncertainty as it requires us to make assumptions and apply judgment to estimate undiscounted future net cash flows related to proved reserves. Such assumptions include commodity prices, capital spending, production and abandonment costs and reservoir data. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs to estimate the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared 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 Financial Statements.

Impairment of Unproved Property

We evaluate our undeveloped crude oil and natural gas leases for impairment on at least a quarterly basis by considering numerous factors that could include nearby drilling results, seismic interpretations, market values of similar assets, existing contracts and future plans for exploration or development. When undeveloped crude oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist mainly of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and to Block P in Equatorial Guinea.

Future Dismantlement, Restoration, and Abandonment Costs

We have significant obligations to remove tangible equipment and restore land and seabed at the end of crude oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of offshore crude oil and natural gas platforms, and capping pipelines. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations.

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A liability for an asset retirement obligation (“ARO”) is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with our crude oil and natural gas properties. We use current retirement costs to estimate the expected cash outflows for asset retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil and natural gas production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. See Note 11 to the Financial Statements for disclosures regarding the asset retirement obligations.

Derivative instruments and hedging activities

We use derivative financial instruments to achieve a more predictable cash flow from crude oil sales by reducing the exposure to price fluctuations. For more information regarding our use of derivative instruments, see Note 10 to the Financial Statements for disclosures.

The Company records balances resulting from commodity risk management activities in the consolidated balance sheets as either assets or liabilities measured at fair value. The significant inputs used to estimate fair value are crude oil prices, volatility, discount rate and the contract terms of the derivative instruments. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the consolidated statements of operations. Gains and losses from the change in fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” and “Cash settlements received on matured derivative contracts, net” lines items located as adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities on the statements of consolidated cash flows. For further discussion, see Note 10 to the Financial Statements.

Business Combinations

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

In estimating the fair values of assets acquired and liabilities assumed in a business combination, various assumptions are made. The most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas 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. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

We estimate the fair values of the acquired assets and assumed liabilities as of the date of the acquisition, and our estimates are subject to adjustment through completion, which is in each case within one year of the acquisition date, based on our ongoing assessments of the fair values of property and equipment, intangible assets, other assets and liabilities and our evaluation of tax positions and contingencies. See Note 4 under “Acquisitions and dispositions” for further discussion.

NEW ACCOUNTING STANDARDS

See Note 3 to the Financial Statements.