The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows:

The Company conducts abandonment studies from time to time to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” in the condensed 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. See Note 12 for further discussion.

On February 28, 2019, the Gabonese branch of an international commercial bank holding the abandonment funds in a U.S. dollar denominated account advised that the bank regulator required transfer of the funds to the Central Bank (“Central Bank”) for the Economic and Monetary Community of Central Africa (“CEMAC”), of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Company’s production sharing contract related to the Etame Marin block located offshore Gabon (“Etame Marin block PSC”) provides that these payments must be denominated in U.S. dollars. The new CEMAC foreign currency regulations provide for the establishment of a U.S. dollar account with the Central Bank. Although the Company requested establishment of such account, the Central Bank did not comply with its requests until February 2021. As a result, the Company was not able to make the annual abandonment funding payments in 2019 and 2020 totaling $2.9 million. In February of 2021, the Central Bank authorized the Company to apply for a U.S. dollar denominated escrow account for the abandonment fund at Citibank Gabon (“Citibank”). The Company, working with Citibank, filed the application to open the account on March 12, 2021 and currently is awaiting the approval of the account from the Central Bank. Amendment No. 5 to the Etame Marin block PSC also provides that in the event the Gabonese bank fails for any reason to reimburse all of the principal and interest due, the Company and other joint interest owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.

Accounts Receivable and Allowance for Doubtful Accounts – The Company’s accounts receivable results from sales of crude oil production and joint interest billings to its joint interest owners for their share of expenses on joint venture projects for which the Company is the operator, as well as from the government of Gabon for reimbursable Value-Added Tax (“VAT”). Collection efforts, including remedies provided for in the contracts, are pursued to collect overdue amounts owed to the Company. Portions of the Company’s costs in Gabon (including the Company’s VAT receivable) are denominated in the local currency of Gabon, the Central African CFA Franc (“XAF”). Most of these receivables have payment terms of 30 days or less. The Company monitors the creditworthiness of the counterparties. Joint interest owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements.

The Company routinely assesses the recoverability of all material receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. When collectability is in doubt, the Company records an allowance against the accounts receivable and a corresponding income charge for bad debts, which appears in the “Bad debt expense and other” line item of the condensed consolidated statements of operations.

As of September 30, 2021 and December 31, 2020, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $14.4 million ($9.6 million, net to VAALCO) and $13.4 million ($4.5 million, net to VAALCO), respectively. The exchange rate was XAF 566.0 = $1.00 and XAF 534.8 = $1.00 at September 30, 2021 and December 31, 2020 respectively. The receivable amount, net of allowances, is reported as a non-current asset in the “Value added tax and other receivables” line item in the condensed consolidated balance sheets. Because both the VAT receivable and the related allowances are denominated in XAF, the exchange rate revaluation of these balances into U.S. dollars at the end of each reporting period also has an impact on the Company’s results of operations. Such foreign currency gains (losses) are reported separately in the “Other, net” line item of the condensed consolidated statements of operations.

The following table provides a roll forward of the aggregate allowance for bad debt:

Derivative Instruments and Hedging Activities – The Company enters into crude oil hedging arrangements from time to time in an effort to mitigate the effects of commodity price volatility and enhance the predictability of cash flows relating to the marketing of a portion of our crude oil production. While these instruments mitigate the cash flow risk of future decreases in commodity prices, they may also curtail benefits from future increases in commodity prices. 

The Company records balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in the 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 condensed consolidated statements of operations. See Note 8 for further discussion.

Fair Value – Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair-value hierarchy are as follows:

Level 1 – Inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives).

Level 2 – Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 – Inputs that are not observable from objective sources, such as internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair-value measurement).

Stock-based compensation – The Company measures the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the date of the grant. The grant date fair value for options or stock appreciation rights (“SARs”) is estimated using either the Black-Scholes or Monte Carlo method depending on the complexity of the terms of the awards granted. The SARs fair value is estimated at the grant date and remeasured at each subsequent reporting date until exercised, forfeited or cancelled.

Black-Scholes and Monte Carlo models employ assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock options or SAR award. These models use the following inputs: (i) the quoted market price of the Company’s common stock on the valuation date, (ii) the maximum stock price appreciation that an employee may receive, (iii) the expected term that is based on the contractual term, (iv) the expected volatility that is based on the historical volatility of the Company’s stock for the length of time corresponding to the expected term of the option or SAR award, (v) the expected dividend yield that is based on the anticipated dividend payments and (vi) the risk-free interest rate that is based on the U.S. treasury yield curve in effect as of the reporting date for the length of time corresponding to the expected term of the option or SAR award.

For restricted stock, the grant date fair value is determined using the market value of the common stock on the date of grant.

The stock-based compensation expense for equity awards is recognized over the requisite or derived service period, using the straight-line attribution method over the service period for each separately vesting portion of the award as if the award was, in-substance, multiple awards.

Unless the awards contain a market condition, previously recognized expense related to forfeited awards is reversed in the period in which the forfeiture occurs. For awards containing a market condition, previously recognized stock-based compensation expense is not reversed when the awards are forfeited. See Note 14 for further discussion.

Fair value of financial instruments – The Company’s assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable, SARs and guarantees. As discussed above, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. With respect to the Company’s other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. There were no transfers between levels for the nine months ended September 30, 2021 and 2020.

Crude Oil and natural gas properties, equipment and other – The Company uses the successful efforts method of accounting for crude oil and natural gas producing activities. Management believes that this method is preferable, as the Company has focused on exploration activities wherein there is risk associated with future success and as such earnings are best represented by drilling results. See Note 7 for further discussion.

Capitalization – 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 (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) 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.

Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block level basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are calculated on a block level basis under the unit-of-production method based upon estimates of proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil and natural gas producing activities, as well as property, plant and equipment unrelated to crude oil and natural gas producing activities, are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which are typically five years for office and miscellaneous equipment and five to seven years for leasehold improvements. See Note 7 for further discussion.

Impairment – The Company reviews the crude oil and natural gas producing properties for impairment on a block level basis whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment charge is recorded based on the fair value of the asset. This may occur if the block contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows. The fair value measurement used in the impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates; the most significant of which is the estimate of net proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Company’s control. Reserve engineering is a subjective process of estimating

underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil and natural gas leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to undeveloped acreage in the Etame Marin block in Gabon and in Block P in Equatorial Guinea. See Note 7 for further discussion.

Purchase Accounting – On February 25, 2021, VAALCO Gabon S.A., a wholly owned subsidiary of the Company, completed the acquisition of Sasol Gabon S.A.’s (“Sasol’s”) 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the sale and purchase agreement (“SPA”) dated November 17, 2020 (the “Sasol Acquisition”). The Company made various assumptions in determining the fair values of acquired assets and liabilities assumed. In order to allocate the purchase price, the Company developed fair value models with the assistance of outside consultants. These fair value models were used to determine the fair value associated with the reserves and applied discounted cash flows to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions. The fair value of working capital assets acquired and liabilities assumed were transferred at book value, which approximates fair value due to the short-term nature of the assets and liabilities. The fair value of the fixed assets acquired was based on estimates of replacement costs and the fair value of liabilities assumed was based on their expected future cash outflows. See Note 3 for further discussion.

Lease commitments – The Company leases office space, marine vessels and helicopters, warehouse and storage facilities, equipment and corporate housing under leasing agreements that expire at various times. All leases are characterized as operating leases and the expense is included in either “production expense” or “general and administrative expense” in the condensed consolidated financial statements. See Note 11 for further discussion.

Asset retirement obligations (“ARO”) – The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of crude oil and natural gas production operations. The 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.

A liability for 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 the crude oil and natural gas properties. The Company uses retirement costs to estimate the expected cash outflows for 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 is adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of the 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. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Depreciation, depletion and amortization” in the Company’s condensed consolidated statements of operations. See Note 12 for disclosures regarding the asset retirement obligations. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 12 for further discussion.

Revenue recognition – Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements (“COSPA”). There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame Marin block PSC is not a customer contract. The Etame Marin block PSC includes provisions for payments to the government of Gabon for: royalties based on 13% of production at the published price and a shared portion of “Profit Oil” (as defined in the Etame Marin block PSC) determined based on daily production rates, as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame Marin block PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments. See Note 6 for further discussion.

Income taxes – The Company’s tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the Company’s tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates 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 the Company’s level of operations or profitability in each jurisdiction impact the Company’s tax liability in any given year.