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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended
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Dec. 31, 2024
Accounting Policies [Abstract] |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of consolidation – The accompanying consolidated financial statements (“Financial Statements”) include the accounts of VAALCO and its wholly owned subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating and non-operating assets are consolidated on a pro rata basis. All intercompany transactions within the consolidated group have been eliminated in consolidation. Use of estimates – The preparation of the Financial Statements in conformity with generally accepted accounting principles in the U.S. (“GAAP”) requires 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. The Financial Statements include amounts that are based on management’s best estimates and judgments. Actual results could differ from those estimates. Estimates of crude oil, natural gas and NGLs reserves used to estimate depletion expense and impairment charges, as well as to estimate the fair value of assets and liabilities acquired in business combinations, require significant judgments and are generally less precise than other estimates made in connection with financial disclosures. Due to inherent uncertainties and the limited nature of data, estimates are imprecise and subject to change over time as additional information becomes available. Cash and cash equivalents – Cash and cash equivalents includes deposits and funds invested in highly liquid instruments with original maturities of three months or less at the date of purchase. The Company maintains its cash accounts in financial institutions that are insured by the Federal Deposit Insurance Corporation. From time to time, cash balances may exceed the insured amounts, however, the Company has not experienced any losses in such accounts and does not believe it is exposed to any significant credit risks associated with cash and cash equivalents. Restricted cash and abandonment funding – Restricted cash includes cash that is contractually restricted. Restricted cash is classified as a current or non-current asset based on its designated purpose and estimated timing of usage. Current amounts in restricted cash at December 31, 2024 and 2023 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at December 31, 2024 and 2023 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 12. Restricted cash also includes a $8.9 million balance for the settlement of a tax audit related to the Svenska Acquisition with a corresponding accrued tax settlement liability recorded and included in Other long-term liabilities in the Consolidated Balance Sheet. 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. The remaining balance of the abandonment fund was unchanged during the remainder of 2024. The Company invests restricted and excess cash in readily redeemable money market funds. The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the consolidated balance sheets to the amounts shown in the consolidated statements of cash flows.
| As of December 31,
| 2024 |  | 2023
| (in thousands)
Cash and cash equivalents | $ | 82,650 |  |  | $ | 121,001 |
Restricted cash - current | 143 |  |  | 114 |
Restricted cash - non-current | 8,665 |  |  | 1,795 |
Abandonment funding | 6,268 |  |  | 6,268 |
Total cash, cash equivalents and restricted cash | $ | 97,726 |  |  | $ | 129,178 |
Trade, net – The Company’s trade accounts receivable results from sales of crude oil, natural gas and NGLs. For credit losses associated with accounts with trade receivables, see allowance for credit losses and other below. Accounts with joint venture owners, net – Accounts with joint venture owners represent the excess of charges billed over cash calls paid by the joint venture owners for exploration, development and production expenditures made by the Company as an operator. Joint owner receivables are secured through cash calls and other mechanisms for collection under the terms of the joint operating agreements. For credit loss and other allowances associated with accounts with joint venture owners, see allowance for credit loss and other below. Egypt receivables and other, net – On January 19, 2022, TransGlobe’s West Gharib, West Bakr and North West Gharib (collectively the “Eastern Desert”) concessions were merged into the Merged Concession Agreement with the Egyptian General Petroleum Corporation (“EGPC”). The Merged Concession includes improved cost recovery and production sharing terms scaled to oil prices with a new 15-year development term and a 5-year extension option. In addition, as of the Merged Concession Effective Date, an effective date adjustment was owed to the Company for the difference in the historic commercial terms and the revised commercial terms applied against the production since the Merged Concession Effective Date (as defined herein) (the “Effective Date Adjustment”). The Company recognized a receivable in connection with the Effective Date Adjustment of $67.5 million as of October 2022, based on historical realized prices (the “Backdated Receivable”). In 2023 and 2024, the Company received payments or provided offsets against the Backdated Receivable. As of December 31, 2024, the remaining net receivable of $33.2 million is recorded in the “Egypt receivables and other” line item on our Consolidated Balance Sheet. For credit losses associated with Egypt receivables and other, net, see allowance for credit losses and other below. Value added tax and other receivables, net – The Company incurs receivables from the government of Gabon for reimbursable Value-Added Tax (“VAT”). As of December 31, 2024 and 2023, the outstanding VAT receivable balance was approximately $6.4 million and $1.6 million, net to VAALCO, 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 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 expense, net” line item of the consolidated statements of operations and comprehensive income. For the allowance associated with VAT, see allowance for credit losses and other below. Allowance for credit losses and other – On January 1, 2023, the Company adopted Accounting Standards Update 2016-13, Financial Instruments—Credit Losses (“ASU 2016-13”). ASU 2016-13 requires an entity to measure credit losses of certain financial assets, including trade receivables, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to form credit loss estimates. All other amounts previously disclosed as allowances for bad debt were transferred to allowances for credit loss and other. The Company estimates the current expected credit loss and other allowances based primarily using either an aging analysis or discounted cash flow methodology that incorporates consideration of current and future conditions that could impact its counterparties’ credit quality and liquidity. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when the Company has determined that the balance will not be collected. The Company has identified the following types of financial assets that are within the scope of ASU 2016-13: •Trade, net; •Accounts with joint venture owners, net; •Egypt receivables and other, net; and •Loans to employees. As a result of adopting ASU 2016-13 on January 1, 2023, the Company recognized a $3.1 million cumulative effect adjustment within retained earnings. During the year ended December 31, 2023, the Company reversed $12.4 million of credit loss and other allowances due to recoveries from VAT and the Sogara refinery. During the year ended December 31, 2024, the Company recognized $7.7 million in credit loss and other allowances mainly due to amounts owed from EGPC, VAT receivables and receivables from joint venture partners. The following table provides an analysis of the change in the aggregate credit loss and other allowances:
| Year Ended December 31,
| 2024 |  | 2023
| (in thousands)
Allowance for credit losses and other |  |  |
Balance at beginning of period | $ | (6,029) |  |  | $ | (8,704) |
Credit losses and other | (6,304) |  |  | (7,543) |
Credit recoveries and other | (1,421) |  |  | 12,449 |
Reversal of allowance resulting from the settlement of the related receivable | 11,200 |  |  | — |
Cumulative effect of adjustment upon adoption of ASU 2016-13 on January 1, 2023 | — |  |  | (3,120) |
Foreign currency gain | — |  |  | 889 |
Balance at end of period | $ | (2,554) |  |  | $ | (6,029) |
Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value. In Gabon and Cote d'Ivoire, inventories represent the Company's share of crude oil produced and stored on the FSO at December 31, 2024 and the FPSO at December 31, 2023, but unsold at the end of each period. In Egypt, inventory consists of the Company's entitlement crude oil barrels not yet sold. Prepayments and other – Included in “Prepayments and other” line item of the Company’s December 31, 2024 and 2023 consolidated balance sheet are the following assets:
| 2024 |  | 2023
| (in thousands)
Egypt advances to contractors | $ | 3,665 |  |  | $ | 2,656 |
Gabon prepaid royalties | 3,089 |  |  | 1,246 |
Deposits | 2,933 |  |  | 726 |
Employee loans and advances | 1,430 |  |  | 1,305 |
Prepaid insurance | 650 |  |  | 474 |
Derivative receivables | 119 |  |  | 403 |
Prepaid fixed asset progress payments | 9 |  |  | 2,314 |
Other prepayments | 3,078 |  |  | 3,310 |
Total prepayments and other | $ | 14,973 |  |  | $ | 12,434 |
Crude oil, natural gas and NGLs properties, equipment, net – The Company uses the successful efforts method of accounting for crude oil, natural gas and NGLs producing activities. •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 (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. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. •Capitalized equipment, spare parts and other – Capitalized equipment, spare parts and other represents the costs incurred in purchasing and bringing the inventory to its present location and condition and is based on purchase costs calculated on weighted average cost basis, including transportation costs. Inventory is classified as long term when the Company expects to utilize the inventory beyond the normal operating cycle. •Depreciation, depletion and amortization – Depletion of wells, platforms, and other production facilities are calculated on a block basis under the unit-of-production method based upon estimates of total proved developed reserves. Depletion of leasehold acquisition costs are provided on a block basis under the unit-of-production method based upon estimates of total proved reserves. Support equipment (other than equipment inventory) and leasehold improvements related to crude oil, natural gas and NGLs producing activities, as well as property, plant and equipment unrelated to crude oil, natural gas and NGLs 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. •Unproved Property Cost – Significant unproved properties are assessed individually for impairment and when events or circumstances indicate that the carrying value of property may not be recovered a valuation allowance is provided if an impairment is indicated. The unproved property costs are not subject to depreciation, depletion and amortization, until they are classified as proved properties. •Impairment – The Company reviews the crude oil, natural gas and NGLs properties and equipment, net for impairment on a block 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 periods of sustained declines in commodity prices. 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, natural gas and NGLs that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil, natural gas and NGLs that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil, natural gas and NGLs sales prices may all differ from those assumed in these estimates. Capitalized equipment inventory is reviewed regularly for obsolescence. When undeveloped crude oil, natural gas and NGLs leases are deemed to be impaired, exploration expense is charged. Unproved property costs consist of acquisition costs related to unproved property costs in the Etame Marin block in Gabon, Canada, Egypt and in Block P in Equatorial Guinea. Lease commitments – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. If a lease is identified within the contract, a determination is made whether the lease qualifies as an operating or financing lease. Regardless of the type of lease, the initial measurement of the lease results in recording a right of use (“ROU”) asset and a lease liability at the present value of the future lease payments. Asset retirement obligations (“ARO”) – The Company has legal obligations to remove tangible equipment and restore land or seabed at the end of crude oil, natural gas and NGLs production operations. The removal and restoration obligations are primarily associated with plugging and abandoning wells, removing and disposing of all or a portion of onshore or offshore crude oil, natural gas and NGLs platforms, and capping pipelines. Estimating the future restoration and removal costs 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 crude oil, natural gas and NGLs properties and equipment, net. The Company uses current 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, natural gas and NGLs properties and equipment, net. 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 capitalized asset retirement cost or through a charged to earnings, as appropriate. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a units-of-production basis for crude oil, natural gas and NGLs properties and equipment, net production facilities, while accretion escalates over the lives of the assets to reach the expected settlement value. 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. Revenue recognition – The Company's revenues are derived from contracts with customers. Royalties are considered to be part of the price of the sale transaction and are therefore presented as a reduction to revenues. Revenues associated with the sale of crude oil, natural gas and NGLs are measured based on the consideration specified in contracts with customers. Revenues from contracts with customers are recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil, natural gas and NGLs usually coincides with title passing to the customer and the customer taking physical possession. VAALCO mainly satisfies its performance obligations at a point in time. Sales and delivery costs associated with certain sales are netted against revenue in accordance with the Company’s policy regarding classification of these type of expenses. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Revenues associated with the sales of the Company’s crude oil, natural gas, condensates and natural gas liquids (“NGLs”) are recognized by reference to actual volumes sold and quoted market prices in active markets for crude oil, natural gas, condensates and NGLs, 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. Major maintenance activities – Costs for major maintenance are expensed in the period incurred and can include the costs of workovers of existing wells, contractor repair services, materials and supplies, equipment rentals and labor costs. 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 awards, 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 period that services are provided. For awards considered liabilities under US GAAP, awards are measured at fair value on the grant date and remeasured at fair value until the award is settled. Legal Contingencies – We are subject to legal proceedings, claims, and liabilities that arise in the ordinary course of business. We accrue losses associated with legal claims when such losses are probable and reasonably estimable. If we determine that a loss is probable and cannot estimate a specific amount for that loss but can estimate a range of loss, the best estimate within the range is accrued. If no amount within the range is a better estimate than any other, the minimum amount of the range is accrued. Estimates are adjusted as additional information becomes available or circumstances change. Legal defense costs associated with loss contingencies are expensed in the period incurred. Foreign currency transactions – The U.S. dollar is the functional currency of the Company’s foreign operating subsidiaries except for Canada which has a functional currency of the Canadian dollar. When the Company’s subsidiaries' functional currency is the US dollar, gains and losses on foreign currency transactions are included in income. When the Company’s subsidiaries functional currency is the local currency, not the US dollar, the cumulative effects of translating the balance sheet accounts from the functional currency into the U.S. dollar at current exchange rates are included in accumulated other comprehensive income (loss). The Company recognized losses on foreign currency transactions of $1.8 million in 2024, $0.9 million in 2023 and $4.2 million in 2022. Income taxes – The 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 annual 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 level of operations or profitability in each jurisdiction would impact the tax liability in any given year. The Company also operates 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 the 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. The Company also records as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil, which is due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted. Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax basis. Deferred tax assets are recognized when it is more likely than not that they will be realized. We periodically assess our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. 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, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, 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 are earnings generated in previous periods, forecasted earnings and the expiration period of carryovers. 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 consolidated balance sheets as either assets or liabilities measured at fair value. The Company has elected not to offset fair value amounts of qualifying derivatives under a master netting arrangement and associated fair value amounts for cash collateral receivables and payables. 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 and comprehensive income (loss). 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 are observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Level 2 – Inputs are observable market-based inputs or unobservable inputs that are corroborated by market data. Level 3 – Inputs are unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. Nonrecurring Fair Value Measurements – The Company applies fair value measurements to its nonfinancial assets and liabilities measured on a nonrecurring basis, which consist of measurements or remeasurements of impairment of crude oil, natural gas and NGLs properties and equipment, net, asset retirement assets and liabilities and assets acquired and liabilities assumed in a business combination. VAALCO uses market-observable prices for assets when comparable transactions can be identified that are similar to the asset being valued. When VAALCO is required to measure fair value and there is not a market-observable price for the asset or for a similar asset then the cost or income approach is used depending on the quality of information available to support management’s assumptions. The cost approach is based on management’s best estimate of the current asset replacement cost. The income approach is based on management’s best assumptions regarding expectations of future net cash flows. The expected cash flows are discounted using a commensurate risk-adjusted discount rate. Such evaluations involve significant judgment, and the results are based on expected future events or conditions such as sales prices, estimates of future oil and gas production or throughput, development and operating costs and the timing thereof, economic and regulatory climates and other factors, most of which are often outside of management's control. However, assumptions used to reflect a market participant's view of long term prices, costs and other factors and are consistent with assumptions used in VAALCO's business plans and investment decisions. Fair value of financial instruments – The Company determines the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs.
|  |  | As of December 31, 2024
| Balance Sheet Line |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
|  |  | (in thousands)
Assets |  |  |  |  |  |  |  |  |
Derivative asset | Prepayments and other |  | $ | — |  |  | $ | 119 |  |  | $ | — |  |  | $ | 119 |
Derivative asset L-T | Other long term assets |  | — |  |  | 1,209 |  |  | — |  |  | 1,209 |
|  |  | $ | — |  |  | $ | 1,328 |  |  | $ | — |  |  | $ | 1,328 |
Liabilities |  |  |  |  |  |  |  |  |
SARs liability | Accrued liabilities and other |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |
Derivative liability | Accrued liabilities and other |  | — |  |  | 17 |  |  | — |  |  | 17 |
|  |  | $ | — |  |  | $ | 17 |  |  | $ | — |  |  | $ | 17 |
|  |  | As of December 31, 2023
| Balance Sheet Line |  | Level 1 |  | Level 2 |  | Level 3 |  | Total
|  |  | (in thousands)
Assets |  |  |  |  |  |  |  |  |
Derivative asset | Prepayments and other |  | $ | — |  |  | $ | 403 |  |  | $ | — |  |  | $ | 403 |
|  |  | $ | — |  |  | $ | 403 |  |  | $ | — |  |  | $ | 403 |
Liabilities |  |  |  |  |  |  |  |  |
SARs liability | Accrued liabilities and other |  | $ | — |  |  | $ | 163 |  |  | $ | — |  |  | $ | 163 |
|  |  | $ | — |  |  | $ | 163 |  |  | $ | — |  |  | $ | 163 |
Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share.

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