VAALCO ENERGY INC /DE/ - Quarter Report: 2022 June (Form 10-Q)

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

See notes to condensed consolidated financial statements.

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

See notes to condensed consolidated financial statements.

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)

See notes to condensed consolidated financial statements.

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

See notes to condensed consolidated financial statements.

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)

See notes to condensed consolidated financial statements.

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.  ORGANIZATION AND ACCOUNTING POLICIES

VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO” or the “Company”) is a Houston, Texas-based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, the Company has production operations and conducts exploration and development activities in Gabon, West Africa. The Company also has opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 below, VAALCO has discontinued operations associated with activities in Angola, West Africa.

The Company’s consolidated subsidiaries are VAALCO Gabon (Etame), Inc., VAALCO Production (Gabon), Inc., VAALCO Gabon S.A., VAALCO Angola (Kwanza), Inc., VAALCO Energy (EG), Inc., VAALCO Energy Mauritius (EG) Limited, VAALCO Energy, Inc. (UK Branch), VAALCO Energy (USA), Inc, VAALCO Energy (International), LLC, VAALCO Energy (Holdings), LLC and VAALCO Energy Canada ULC, an unlimited liability company incorporated under the laws of the Province of Alberta and a wholly owned subsidiary of the Company.

These condensed consolidated financial statements have been prepared in accordance with rules of the Securities and Exchange Commission (“SEC”) and do not include all the information and disclosures required by accounting principles generally accepted in the United States (“GAAP”) for complete financial statements. They should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2021, which includes a summary of the significant accounting policies.

With respect to the novel strain of coronavirus (“COVID-19”), during 2021, and continuing in 2022, crude oil prices have experienced significant improvement and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. However during the second quarter of 2022 the BA.5 strain of the Omicron variant caused surges in infections worldwide. While COVID-19 related travel restrictions have gradually eased as governments and people continue to have increasing access to vaccines that help reduce the spread of COVID-19, new surges in infections and hospitalizations could alter the current environment. The significant decline in oil prices experienced in 2020 was, in part, due to disruptions in the worldwide economy due to the COVID-19 pandemic which quarantined people and restricted travel. To date the Company's operations have not been materially impacted by COVID-19, and worldwide we are seeing improving economic activity while managing the risk of a resurgence, but there can be no guarantees that COVID-19 will not have an impact on the Company or its operations.

In July 2021, OPEC+ agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022. The decision to continue to increase production was reaffirmed by an OPEC+ meeting held on August 3, 2022. The average Brent crude oil price for the three months ended June 30, 2021, September 30, 2021,  December 31, 2021, March 31, 2022 and June 30, 2022 was $69 per barrel, $73 per barrel, $79 per barrel, $100 per barrel and $113 per barrel, respectively.

While the current community price environment is favorable and the Company has not experienced disruptions to its operations as a result of COVID-19 any new outbreak or emergence of a new variant  may have a material adverse impact on financial results and business operations of the Company, including the timing and ability of the Company to complete future drilling campaigns and other efforts required to advance the development of its crude oil and natural gas properties.

Principles of consolidation – The accompanying condensed 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 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 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.

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.

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 time duration. Current amounts in restricted cash at June 30, 2022 and 2021 each include an escrow amount for the floating, production, storage and offloading vessel (“FPSO”), representing bank guarantees for customs clearance in Gabon. Long-term amounts at June 30, 2022 and 2021 include a charter payment escrow for the FPSO offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. 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 condensed consolidated balance sheets to the amounts shown in the condensed consolidated statements of cash flows.

The Company conducts regular abandonment studies 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” on 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 10 for further discussion.

On February 28, 2019, the Gabonese branch of the 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 African Economic and Monetary Community (“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 PSC”) provides these payments must be denominated in U.S. dollars and the CEMAC 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, 2020 or 2021 totaling $4.3 million, net to VAALCO based on the 2018 abandonment study. In February of 2021, the Bank of Central African State (“BEAC”) authorized the Company to apply for a U.S. dollar denominated escrow account for the abandonment fund at Citibank Gabon (“Citibank”). Working with Citibank, on March 12, 2021 the Company filed the application to open the account and is currently awaiting the approval of the account from the Central Bank. Accordingly, the Company was not able to make our funding payment in 2021. In December 2021, as part of the new FX regulations issued by BEAC, BEAC allowed for the opening of U.S. dollars escrow accounts for the abandonment funds at BEAC. The Company is currently working with the extractive industry to formulate the agreements, which are expected to be finalized in 2022, that regulate these accounts. Accordingly, pursuant to Amendment No. 5 of the Etame PSC that required these funds to be in U.S. dollars, once the account for the U.S. dollars abandonment fund is open at BEAC we will resume our funding of the abandonment fund in compliance with the Etame PSC.

Accounts with joint venture owners – 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.

Accounts Receivable and Allowance for Doubtful Accounts – The Company’s accounts receivable results from sales of crude oil production, joint interest billings to its joint interest owners for their share of expenses on joint venture projects for which the Company is the operator, and receivables 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. Joint 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 June 30, 2022, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $17.4 million ($10.6 million, net to VAALCO). As of June 30, 2022, the exchange rate was XAF 627.6 = $1.00. As of December 31, 2021, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $14.5 million ($9.6 million, net to VAALCO). As of December 31, 2021, the exchange rate was XAF 578.2 = $1.00. 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:

Other receivables, net – Under the terms of the Etame PSC, the Company can be required to contribute to meeting domestic market needs of the Republic of Gabon by delivering to it, or another entity designated by the Republic of Gabon, an amount of crude oil proportional to the Company’s share of production to the total production in Gabon over the year. In 2021, the Company was notified by the Republic of Gabon to deliver to a refinery its proportionate share of crude oil to meet the domestic market need as per the terms of the Etame PSC. The Company is entitled, per the Etame PSC, to a fixed selling price for the oil delivered. Since the crude-oil produced by the Company was not compatible with the crude-oil requirements of the refinery, the Company entered into two contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that produced  the compatible oil the refinery needs and another contract with the refinery itself to deliver the crude oil to. Under the contract with the provider of the crude oil, the third party provider is entitled to a selling price consistent with the price the Company receives under the terms of the Etame PSC for the delivery of the crude oil to the refinery. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid for by the refinery, included in the Company’s June 30, 2022 condensed consolidated balance sheet are current receivables in the "other, net" line item of approximately $10.7 million for amounts due to the Company from the refinery for 195 MBbls delivered in April and May 2022, a $19.1 million current liability included in the "Accrued liabilities and other" line item for amounts due to the oil supplier for 163 MBbls of crude oil purchased in April and June 2022 and $12.6 million included in current assets on the "Crude oil inventory" line item for 98 MBbls of crude oil procured in June 2022, which is 98 MBbls of the 163 MBbls included in accrued liabilities.

Crude oil inventory – Crude oil inventories are carried at the lower of cost or net realizable value and represent the share of crude oil produced and stored on the FPSO, but unsold at the end of the period and crude oil purchased in order to comply with the domestic market needs of the Republic of Gabon.  As of June 30, 2022 the crude oil inventory associated with the domestic market needs obligation was $12.6 million and the amount related to unsold crude oil inventory was $1.3 million.

Prepayments and Other – Included in “Prepayments and other” line item of the condensed consolidated balance sheet for the six months ended  June 30, 2022 are $6.0 million of prepayments related to fixed assets.

Materials and supplies – Materials and supplies, which are included in the “Prepayments and other” line item of the condensed consolidated balance sheet, are primarily used for production related activities. These assets are valued at the lower of cost, determined by the weighted-average method, or net realizable value.

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.

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. 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 basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a block 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 three to five years for office and miscellaneous equipment and five to seven years for leasehold improvements.

Impairment – The Company reviews the crude oil and natural gas producing properties 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 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 (as defined in the policy "Fair value" below) 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 – At inception, contracts are reviewed to determine whether an agreement contains a lease as defined under Accounting Standards Codification (“ASC”) 842, Leases. Further, 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. ROU assets for operating leases are recorded under “Right of use operating lease assets” and the current portion and long-term portion of the lease liabilities for operating leases are reflected in “Operating lease liabilities – current portion” and “Operating lease liabilities – net of current portion” within the condensed consolidated balance sheets. ROU assets for financing leases are recorded within “Right of use financing lease assets” and the current portion and long-term portion of the lease liabilities for financing leases are reflected in “Financing lease liabilities – current portion” and “Financing lease liabilities – net of current portion” within the condensed consolidated balance sheets.

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 crude oil and natural gas properties. 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 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. 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 13 for further discussion.

Revenue recognition – Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements. 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 PSC. The Etame PSC is not a customer contract. The terms of the Etame 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” 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 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.

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, 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 15 for further discussion.

Income taxes – The annual 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 and natural gas 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. We also record as income tax expense the increase or decrease in the value of the government’s allocation of Profit Oil which results due to changes in value from the time the allocation is originally produced to the time the allocation is actually lifted.

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.

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the expectations change regarding the expected future tax consequences, the Company may be required to record additional deferred taxes that could have a material effect on the condensed consolidated financial position and results of operations. See Note 16 for further discussion.

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 fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments 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 internally developed present value of future cash flows model that underlies the fair-value measurement).

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 and natural gas properties, asset retirement assets and liabilities and other long-lived assets and assets acquired and liabilities assumed in a business combination. Generally, a cash flow model is used in combination with inflation rates and credit-adjusted, risk-free discount rates or industry rates to determine the fair value of the assets and liabilities. Based upon our review of the fair value hierarchy, the inputs used in these fair value measurements are considered Level 3 inputs.

Fair value of financial instruments – The Company’s current assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets and liabilities, accounts payable, liabilities for SARs and guarantees. As discussed further in Note 8, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. The derivatives referenced below are reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. SARs liabilities are measured and reported at fair value using Level 2 inputs each period with changes in fair value recognized in net income. The SARs liabilities is reported in “Accrued liabilities and other” on the condensed consolidated balance sheet. With respect to the 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.

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. See Note 5 for further discussion. 

2.  NEW ACCOUNTING STANDARDS

Not Yet Adopted

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Codification (“ASU”) No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”) related to the calculation of credit losses on financial instruments. All financial instruments not accounted for at fair value will be impacted, including the Company’s trade and joint venture owners’ receivables. Allowances are to be measured using a current expected credit loss (“CECL”) model as of the reporting date that is based on historical experience, current conditions and reasonable and supportable forecasts. This is significantly different from the current model that increases the allowance when losses are probable. Initially, ASU 2016-13 was effective for all public companies for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years and will be applied with a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective.  The FASB subsequently issued ASU No. 2019-04 (“ASU 2019-04”): Codification Improvements to Topic 326, Financial Instruments-Credit Losses, Topic 815, Derivatives, and Topic 825, Financial Instruments and ASU No. 2019-05 (“ASU 2019-05”): Financial Instruments-Credit Losses (Topic 326) - Targeted Transition Relief. ASU 2019-04 and ASU 2019-05 provide certain codification improvements related to implementation of ASU 2016-13 and targeted transition relief consisting of an option to irrevocably elect the fair value option for eligible instruments.  In November 2019, the FASB issued ASU No. 2019-10, Financial Instruments—Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates. This amendment deferred the effective date of ASU No. 2016-13 from January 1, 2020 to January 1, 2023 for calendar year end smaller reporting companies, which includes the Company.  The Company plans to defer the implementation of ASU 2016-13, and related updates, until January 2023.

3. ACQUISITIONS AND DISPOSITIONS

Pending Merger

On July 13, 2022, the Company and VAALCO Energy Canada ULC (“AcquireCo”), an Alberta unlimited liability company and an indirect wholly owned subsidiary of the Company, entered into an Arrangement Agreement (the “Arrangement Agreement”) with TransGlobe Energy Corporation, an Alberta corporation (“TransGlobe”), pursuant to which, among other things, AcquireCo agreed to acquire all of the issued and outstanding common shares of TransGlobe (the “Arrangement”), with TransGlobe continuing as a direct wholly owned subsidiary of AcquireCo and an indirect wholly-owned subsidiary of the Company. The aggregate consideration for the Arrangement is approximately $307 million. The $307 million aggregate consideration is estimated from the Company's share price of $6.23 at the close of business on July 13, 2022 multiplied by the exchange ratio negotiated with TransGlobe of 0.6727 shares of the Company's stock for each TransGlobe share multiplied by the number of TransGlobe outstanding shares of 73,309,064.  The Arrangement will be implemented by way of a plan of arrangement (the “Plan of Arrangement”) in accordance with the Business Corporations Act (Alberta) (the “ABCA”) and is subject to approval by the Court of Queen’s Bench of Alberta (the “Court”), the stockholders of the Company and the shareholders of TransGlobe, among other customary conditions for a transaction of this nature and size.

On the terms and subject to the conditions of the Arrangement Agreement and the Plan of Arrangement, at the effective time of the Arrangement (the “Effective Time”), each common share of TransGlobe that is issued and outstanding immediately prior to the Effective Time will be deemed to be transferred and assigned to AcquireCo in exchange for 0.6727 of a share (“Exchange Ratio”) of VAALCO common stock (the “Consideration”). No fractional shares of VAALCO common stock will be issued in the Arrangement, and TransGlobe’s shareholders will receive cash in lieu of any fractional shares of VAALCO common stock. Any shares in respect of which dissent rights have been properly exercised and not withdrawn pursuant to Section 191 of the ABCA, will be deemed to be transferred and assigned to VAALCO, but will not be entitled to the Consideration and will, instead, be subject to dissent rights under the ABCA, as modified by the Plan of Arrangement and the interim order of the Court.

The shareholders of TransGlobe will be asked to approve the Arrangement (the “TransGlobe Resolution”) at a shareholder meeting, and the stockholders of VAALCO will be asked to approve (i) the issuance of shares of VAALCO common stock as Consideration for the Arrangement (the “Consideration Shares”) (the “VAALCO Share Issuance Resolution”); and (ii) an amendment to VAALCO’s certificate of incorporation to increase the size of VAALCO’s authorized share capital (the “VAALCO Amendment Resolution” and, together with the VAALCO Share Issuance Resolution, the “VAALCO Resolutions”) at a stockholder meeting. VAALCO will use commercially reasonable efforts to schedule its stockholder meeting as promptly as reasonably practicable following clearance by the SEC of VAALCO’s proxy statement relating to such meeting and on the same date as the TransGlobe’s shareholder meeting.  TransGlobe will use its commercially reasonable efforts to schedule its shareholder meeting on the same date as VAALCO’s stockholder meeting.

The closing of the Arrangement is conditioned on the adoption of the TransGlobe Resolution and the VAALCO Resolutions. Consummation of the Arrangement is also subject to (a) the approval of the Arrangement by the Court in form and substance acceptable to each of VAALCO and TransGlobe, acting reasonably; (b) the absence of any law, injunction or other governmental order that prohibits the consummation of the Arrangement; (c) the approval for listing on the NYSE of the Consideration Shares; (d) the U.K. Financial Conduct Authority (the “FCA”) shall have acknowledged that the application for admission of VAALCO’s enlarged share capital has been approved and (after satisfaction of any conditions to which such approval is expressed to be subject (“U.K. Listing Conditions”)), such admission will become effective as soon as a dealing notice has been issued by the FCA and any U.K. Listing Conditions having been satisfied; (e) the LSE shall have acknowledged that the conditions to VAALCO’s enlarged share capital being admitted to trading on the standard segment of the main market of the LSE have been satisfied; (f) the availability of an exemption of Consideration Shares from the registration requirements of the Securities Act of 1933 (the “Securities Act”) under Section 3(a)(10) thereof; (g) the absence of a material adverse effect in respect of either TransGlobe or VAALCO; (h) to the extent required or necessary, (1) the approval or consent of, or waiver or non-exercise of any material termination, pre-emption or similar rights by, any governmental entity in, or in respect of the interests held by TransGlobe in, Canada and Egypt and (2) no actions or inactions having been taken which are likely to result in the withdrawal, cancellation, termination or modification of any license or permit held by TransGlobe or any of its subsidiaries in respect of the interests held by TransGlobe in Canada and Egypt which is necessary for the proper carrying on of its business; (i) dissent rights not having been exercised (or if exercised, remaining unwithdrawn) with respect to more than 10% of the issued and outstanding TransGlobe shares; and (j) other customary closing conditions, including the accuracy of the other party’s representations and warranties (subject to certain materiality qualifications), and the other party’s compliance with its covenants and agreements contained in the Arrangement Agreement.

If consummated, the Arrangement will result in VAALCO stockholders owning approximately 54.5%, and TransGlobe shareholders owning approximately 45.5%, of the combined company, calculated based on vested outstanding shares of each company outstanding as of the date of the Arrangement Agreement. The Arrangement is expected to be completed before the end of 2022.

The Arrangement Agreement provides for mutual termination fees of $9.15 million in the event the Arrangement Agreement is terminated by either party in certain circumstances.

For the three and six months ended June 30, 2022 included in the line item "Other (expense) income, net" is $1.2 million of transactions costs associated with the Arrangement with TransGlobe.

Acquisition of Sasol Gabon S.A.’s Interest in Etame

On February 25, 2021, VAALCO Gabon S.A. 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, the Company owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased the Company’s working interest 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.

The following amounts represent the allocation of the purchase price to the assets acquired and liabilities assumed in the Sasol Acquisition.

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. The Company used estimated future crude oil prices as of the closing date, February 25, 2021, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using the Company’s weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The Company had one year from the date of closing to record purchase price adjustments as a result of changes in such estimates. 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 $5.5 million is included in “Other, net" under "Other income (expense)" in the 2021 condensed consolidated statements of operations. An income tax benefit of $2.2 million, related to the bargain purchase gain, is also included in the 2021 condensed consolidated statements of operations.

The impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $52.4 million and $84.8 million for the three and six months ended June 30, 2022, respectively, and $7.1 million and $12.9 million increase to “Net income” in the condensed consolidated statements of operations for the three and six months ended June 30, 2022, respectively.

The impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $22.2 million and $31.6 million for the three and six months ended June 30, 2021, respectively, and $8.1 million and $9.9 million increase to “Net income” in the condensed consolidated statements of operations for the three and six months ended June 30, 2021, respectively.

The unaudited pro forma results presented below have been prepared to give the effect to the Sasol Acquisition discussed above on the Company’s results of operations for the three and six months ended June 30, 2021, respectively, as if the Sasol Acquisition had been consummated on January 1, 2020. The unaudited pro forma results do not purport to represent what the Company’s actual results operations would have been if the Sasol Acquisition had been completed on such date or to project the Company’s results of operations for any future date or period.

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, the Company paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.

Discontinued Operations - Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40%, and the Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA and reduced its activities in Angola. As a result of this strategic shift, the Company classified all the related assets and liabilities as those of discontinued operations in the condensed consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the Company’s condensed consolidated statements of operations. The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s condensed consolidated statements of cash flows. During three and six months ended June 30, 2022 and 2021, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

4. SEGMENT INFORMATION 

The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s two reportable operating segments is organized and managed based upon geographic location. The Company’s Chief Executive Officer, who is the chief operating decision maker, and management review and evaluate the operation of each geographic segment separately, primarily based on operating income (loss). The operations of all segments include exploration for and production of hydrocarbons where commercial reserves have been found and developed. Revenues are based on the location of hydrocarbon production. Corporate and other is primarily corporate and operations support costs that are not allocated to the reportable operating segments.

Segment activity of continuing operations for the three and six months ended June 30, 2022 and 2021 as well as long-lived assets and segment assets at June 30, 2022 and December 31, 2021 are as follows:

(1)    Excludes assets acquired in the Sasol acquisition.

(1)    Excludes assets acquired in the Sasol acquisition.

Information about the Company’s most significant customers

The Company currently sells crude oil production from Gabon under term crude oil sales and purchase agreements (“COSPAs”) or crude oil sales and marketing agreements ("COSMA or COSMAs") with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The Company signed a COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that covered sales from February 2020 through January 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. The COSPA with Exxon was amended and extended several times, most recently in January 2022, extending the date of the COSPA through the end of July 2022. 

As discussed further in Note 11, on May 16, 2022, VAALCO Gabon (Etame), Inc. (the “Borrower”) entered into a facility agreement (the “Facility Agreement”) by and among the Company, VAALCO Gabon, SA (“VAALCO Gabon”), 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 initial aggregate maximum principal amount available of up to $50.0 million. In connection with the entry into the Facility Agreement, the Company entered into a COSMA with Glencore pursuant to which the Company agreed to make Glencore the exclusive offtaker and marketer of all of the crude oil produced from the Etame G4-160 Block, offshore Gabon during the period from August 1, 2022 until the Final Maturity Date of the Facility (as defined in the Facility Agreement). Pursuant to the COSMA, Glencore agreed to buy and market the Company’s crude oil with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

During the three and six months ended June 30, 2022 and 2021, revenues from sales of crude oil to Exxon were 100% of the Company’s total revenues from customers.

5.  EARNINGS PER SHARE

Basic earnings per share (“EPS”) is calculated using the average number of shares of common stock outstanding during each period. For the calculation of diluted shares, the Company assumes that restricted stock is outstanding on the date of vesting, and the Company assumes the issuance of shares from the exercise of stock options using the treasury stock method.

A reconciliation of reported net income (loss) to net income (loss) used in calculating EPS as well as a reconciliation from basic to diluted shares follows:  

6. REVENUE

Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs or COSMAs. COSPAs or COSMAs with customers are renegotiated near the end of the contract term and may be entered into with a different customer or the same customer going forward. Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA or COSMAs. See Note 4 under “Information about the Company’s most significant customers” for further discussion.

Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. 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. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings that occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations. 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. 

The Company accounts for production imbalances as a reduction in reserves. The volumes sold may be more or less than the volumes that the Company is entitled based on the ownership interest in the property, and the Company would recognize a liability if the existing proved reserves were not adequate to cover an imbalance.

For each lifting completed under a COSPA or COSMA, payment is made by the customer in U.S. dollars by electronic transfer 30 days after the date of the bill of lading. For each lifting of crude oil, pricing is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors.

Generally, no significant judgments or estimates are required as of a given filing date with regard to applicable price or volumes sold because all of the parameters are known with certainty related to liftings that occurred in the recently completed calendar quarter. As such, the Company deemed this situation to be characterized as a fixed price situation.

In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame PSC. The Etame PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the Etame 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” 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 PSC provides that the government of Gabon may settle these obligations in-kind, i.e. taking crude oil barrels, rather than with cash payments.

To date, the government of Gabon has not elected to take its royalties in-kind, and this obligation is settled through a monthly cash payment. Payments for royalties are reflected as a reduction in revenues from customers. Should the government elect to take the production attributable to its royalty in-kind, the Company would no longer have sales to customers associated with production assigned to royalties.

With respect to the government’s share of Profit Oil, the Etame PSC provides that the corporate income tax liability may be satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected in the current provision for income tax expense. Prior to February 1, 2018, the government did not take any of its share of Profit Oil in-kind. These revenues have been included in revenues to customers as the Company entered into the contract with the customer to sell the crude oil and was subject to the performance obligations associated with the contract. For the in-kind sales by the government beginning February 1, 2018, these sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame PSC is reflected as revenue with an offsetting amount reported as a current income tax expense. Payments of the income tax expense are reported in the period that the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. The Company has a $29.2 million foreign income tax payable as of June 30, 2022. As of December 31, 2021, the foreign taxes payable attributable to this obligation was $3.1 million.

Certain amounts associated with the carried interest in the Etame Marin block discussed above are reported as revenues. In this carried interest arrangement, the carrying parties, which include the Company and other working interest owners, are obligated to fund all of the working interest costs that would otherwise be the obligation of the carried party. The carrying parties recoup these funds from the carried interest party’s revenues.

The following table presents revenues from contracts with customers as well as revenues associated with the obligations under the Etame PSC.