May 3, 2022 - 10-Q: Quarterly report pursuant to Section 13 or 15(d)

Form: 10-Q

Documents

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

FORM 10-Q

________________________________

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2022

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______ to _______

Commission file number 1-32167

________________________________

VAALCO Energy, Inc.

(Exact name of registrant as specified in its charter)

________________________________


Delaware		76-0274813
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

9800 Richmond Avenue Suite 700 Houston, Texas		77042
(Address of principal executive offices)		(Zip code)

(713) 623-0801

(Registrant’s telephone number, including area code)

________________________________

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading symbol(s)	Name of each exchange on which registered
Common Stock	EGY	New York Stock Exchange
Common Stock	EGY	London Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No x

As of April 30, 2022, there were outstanding 58,902,069 shares of common stock, $0.10 par value per share, of the registrant.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets
March 31, 2022 and December 31, 2021	2
Condensed Consolidated Statements of Operations
Three Months Ended March 31, 2022 and 2021	3
Condensed Consolidated Statements of Shareholders’ Equity
Three Months Ended March 31, 2022 and 2021	4
Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, 2022 and 2021	5
Notes to Condensed Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37
ITEM 4. CONTROLS AND PROCEDURES	38
PART II. OTHER INFORMATION	38
ITEM 1. LEGAL PROCEEDINGS	38
ITEM 1A. RISK FACTORS	38
ITEM 6. EXHIBITS	39

Unless the context otherwise indicates, references to “VAALCO,” “the Company”, “we,” “our,” or “us” in this Quarterly Report on Form 10-Q are references to VAALCO Energy, Inc., including its wholly-owned subsidiaries.

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)



	As of March 31, 2022		As of December 31, 2021
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	18,939	$	48,675
Restricted cash		4,230		79
Receivables:
Trade, net		44,616		22,464
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented		3,764		345
Other, net		11,612		9,977
Crude oil inventory		4,634		1,593
Prepayments and other		8,408		5,156
Total current assets		96,203		88,289

Crude oil and natural gas properties, equipment and other - successful efforts method, net		121,935		94,324
Other noncurrent assets:
Restricted cash		1,752		1,752
Value added tax and other receivables, net of allowance of $6.1 million and $5.7 million, respectively		5,692		5,536
Right of use operating lease assets		6,872		10,227
Right of use finance lease assets		1,795		—
Deferred tax assets		50,296		39,978
Abandonment funding		21,369		21,808
Other long-term assets		2,596		1,176
Total assets	$	308,510	$	263,090
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	10,509	$	18,797
Accounts with joint venture owners		—		3,233
Accrued liabilities and other		91,409		49,444
Operating lease liabilities - current portion		6,429		9,642
Finance lease liabilities - current portion		341		—
Foreign income taxes payable		8,819		3,128
Current liabilities - discontinued operations		7		13
Total current liabilities		117,514		84,257
Asset retirement obligations		34,377		33,949
Operating lease liabilities - net of current portion		461		587
Finance lease liabilities - net of current portion		1,411		-
Total liabilities		153,763		118,793
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued		—		—
Common stock, $0.10 par value; 100,000,000 shares authorized, 69,862,217 and 69,562,774 shares issued, 58,858,901 and 58,623,451 shares outstanding, respectively		6,986		6,956
Additional paid-in capital		77,272		76,700
Less treasury stock, 11,003,316 and 10,939,323 shares, respectively, at cost		(44,234)		(43,847)
Retained earnings		114,723		104,488
Total shareholders' equity		154,747		144,297
Total liabilities and shareholders' equity	$	308,510	$	263,090

See notes to condensed consolidated financial statements.
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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)


	Three Months Ended March 31,
	2022		2021
	(in thousands, except per share amounts)
Revenues:
Crude oil and natural gas sales	$	68,656	$	39,774
Operating costs and expenses:
Production expense		18,360		16,133
Exploration expense		127		142
Depreciation, depletion and amortization		4,673		4,148
General and administrative expense		4,994		4,547
Bad debt expense and other		492		101
Total operating costs and expenses		28,646		25,071
Other operating expense, net		(5)		(360)
Operating income		40,005		14,343
Other income (expense):
Derivative instruments loss, net		(31,758)		(5,954)
Interest (expense) income, net		(3)		5
Other (expense) income, net		(696)		4,580
Total other expense, net		(32,457)		(1,369)
Income from continuing operations before income taxes		7,548		12,974
Income tax (benefit) expense		(4,628)		3,086
Income from continuing operations		12,176		9,888
Income loss from discontinued operations, net of tax		(12)		(19)
Net income	$	12,164	$	9,869

Basic net income per share:
Income from continuing operations	$	0.21	$	0.17
Loss from discontinued operations, net of tax		—		—
Net income per share	$	0.21	$	0.17
Basic weighted average shares outstanding		58,702		57,636
Diluted net income per share:
Income from continuing operations	$	0.20	$	0.17
Loss from discontinued operations, net of tax		—		—
Net income per share	$	0.20	$	0.17
Diluted weighted average shares outstanding		59,179		58,461

See notes to condensed consolidated financial statements.
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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings		Total
	(in thousands)
Balance at January 1, 2022	69,562	(10,939)	$	6,956	$	76,700	$	(43,847)	$	104,488	$	144,297
Shares issued - stock-based compensation	300	(64)		30		168		—		—		198
Stock-based compensation expense	—	—		—		404		—		—		404
Treasury stock	—	—		—		—		(387)		—		(387)
Dividend Distribution	—	—		—		—		—		(1,929)		(1,929)
Net income	—	—		—		—		—		12,164		12,164
Balance at March 31, 2022	69,862	(11,003)	$	6,986	$	77,272	$	(44,234)	$	114,723	$	154,747


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings		Total
	(in thousands)
Balance at January 1, 2021	67,897	(10,366)	$	6,790	$	74,437	$	(42,421)	$	22,652	$	61,458
Shares issued - stock-based compensation	431	(155)		43		304		—		—		347
Stock-based compensation expense	—	—		—		323		—		—		323
Treasury stock	—	—		—		—		(403)		—		(403)
Net income	—	—		—		—		—		9,869		9,869
Balance at March 31, 2021	68,328	(10,521)	$	6,833	$	75,064	$	(42,824)	$	32,521	$	71,594

See notes to condensed consolidated financial statements.
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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Three Months Ended March 31,
	2022		2021
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	12,164	$	9,869
Adjustments to reconcile net income to net cash (used in) provided by operating activities:
Loss from discontinued operations, net of tax		12		19
Depreciation, depletion and amortization		4,673		4,148
Bargain purchase gain		—		(7,651)
Deferred taxes		(10,318)		1,809
Unrealized foreign exchange loss (gain)		116		(400)
Stock-based compensation		1,422		1,559
Cash settlements paid on exercised stock appreciation rights		(205)		(852)
Derivative instruments loss, net		31,758		5,954
Cash settlements paid on matured derivative contracts, net		(12,500)		(1,710)
Bad debt expense and other		492		101
Other operating expense, net		5		360
Operational expenses associated with equipment and other		240		247
Cash advance for other long-term assets		(1,452)		—
Change in operating assets and liabilities:
Trade receivables		(22,152)		(12,647)
Accounts with joint venture owners		(6,652)		275
Other receivables		(1,723)		(53)
Crude oil inventory		(3,041)		5,795
Prepayments and other		(876)		(3,240)
Value added tax and other receivables		(1,076)		(149)
Accounts payable		(10,132)		(6,627)
Foreign income taxes receivable/payable		5,691		5,524
Accrued liabilities and other		12,814		(576)
Net cash (used in) provided by continuing operating activities		(740)		1,755
Net cash used in discontinued operating activities		(18)		(13)
Net cash (used in) provided by operating activities		(758)		1,742
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(23,148)		(1,198)
Acquisition of crude oil and natural gas properties		—		(17,858)
Net cash used in continuing investing activities		(23,148)		(19,056)
Net cash used in discontinued investing activities		—		—
Net cash used in investing activities		(23,148)		(19,056)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		198		347
Dividend distribution		(1,929)		—
Treasury shares		(387)		(403)
Net cash used in continuing financing activities		(2,118)		(56)
Net cash used in discontinued financing activities		—		—
Net cash used in financing activities		(2,118)		(56)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(26,024)		(17,370)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		72,314		61,317
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	46,290	$	43,947

See notes to condensed consolidated financial statements.
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VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)


	Three Months Ended March 31,
	2022		2021
	(in thousands)
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	26,113	$	3,137
Recognition of right-of-use finance lease assets and liabilities	$	1,851	$	—
Asset Retirement Obligations	$	—	$	14,564

See notes to condensed consolidated financial statements.

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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) and VAALCO Energy (USA), Inc.

These condensed consolidated financial statements are unaudited, but in the opinion of management, reflect all adjustments necessary for a fair presentation of results for the interim periods presented. All adjustments are of a normal recurring nature unless disclosed otherwise. Interim period results are not necessarily indicative of results expected for the full year.

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. 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. Further there are indicators of improving economic activity to pre-COVID-19 levels while managing the risk of a resurgence.

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 March 31, 2022. For the three months ended March 31, 2022, the average brent crude oil price was over $100 per barrel. The average brent crude oil price for the three months ended March 31, 2021, June 30, 2021, September 30, 2021 and December 31, 2021 was $61 per barrel, $69 per barrel, $73 per barrel and $79 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 generally accepted accounting principles in the United States (“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.

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 March 31, 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 and funds paid in advance to a counterparty related to the Company’s derivative transactions (see Note 8 for further discussion). Long-term amounts at March 31, 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.

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	As of March 31,
	2022		2021
	(in thousands)
Cash and cash equivalents	$	18,939	$	19,251
Restricted cash - current		4,230		82
Restricted cash - non-current		1,752		1,752
Abandonment funding		21,369		22,862
Total cash, cash equivalents and restricted cash	$	46,290	$	43,947

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. The Company monitors the creditworthiness of the counterparties, and it has obtained credit enhancements from some parties in the form of parental guarantees or letters of credit. 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 March 31, 2022, the outstanding VAT receivable balance, excluding the allowance for bad debt, was approximately $15.8 million ($10.2 million, net to VAALCO). As of March 31, 2022, the exchange rate was XAF 590.1 = $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.

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


	Three Months Ended March 31,
	2022		2021
	(in thousands)
Allowance for bad debt
Balance at beginning of period	$	(5,741)	$	(2,273)
Bad debt charge, net of receipts		(492)		(101)
Adjustment associated with Sasol Acquisition		—		(2,879)
Foreign currency gain		98		161
Balance at end of period	$	(6,135)	$	(5,092)

Other receivables– 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 2 contracts to fulfill its domestic market needs obligation under the Etame PSC. One contract was to purchase oil from another producer that was more compatible to the refinery and another contract with the refinery itself to deliver the crude oil to. Under the contract with another producer, the producer is entitled to a selling price consistent with the price the Company receives under the terms of the Etame PSC. As a result of these contracts and timing differences between when the oil is procured and when it is delivered to and paid by the refinery, included in the Company’s March 31, 2022 condensed consolidated balance sheet is other receivables of approximately $11.6 million for amounts due to the Company from the refinery and a $11.6 million liability included in accrued liabilities for amounts due to the oil supplier.

Prepayments and Other– Included in “Prepayments and other” line item of the condensed consolidated balance sheet for the three months ended March 31, 2022 are $3.9 million of prepayments related to fixed assets and $2.1 million of prepayments related to royalty expenses.

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.

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 five years for office and miscellaneous equipment and five to seven years for leasehold improvements.

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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 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 12 for further discussion.

Revenue recognition– Revenues from contracts with customers are generated from sales in Gabon pursuant to crude oil sales and purchase agreements. 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

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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 14 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 15 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.

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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.


		As of March 31, 2022
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	1,422	$	—	$	1,422
Derivative liability - crude oil swaps	Accrued liabilities and other		—		24,064		—		24,064
		$	—	$	25,486	$	—	$	25,486

		As of December 31, 2021
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Liabilities
SARs liability	Accrued liabilities and other	$	—	$	609	$	—	$	609
Derivative liability - crude oil swaps	Accrued liabilities and other		—		4,806		—		4,806
		$	—	$	5,415	$	—	$	5,415

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.

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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

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.


		February 25, 2021
		(in thousands)
Purchase Consideration
Cash	$	33,959
Fair value of contingent consideration		4,647
Total purchase consideration	$	38,606

		February 25, 2021
		(in thousands)
Assets acquired:
Wells, platforms and other production facilities	$	37,176
Equipment and other		5,568
Value added tax and other receivables		1,234
Abandonment funding		11,781
Accounts receivable - trade		11,220
Other current assets		3,963
Liabilities assumed:
Asset retirement obligations		(14,564)
Accrued liabilities and other		(10,121)
Bargain purchase gain		(7,651)
Total purchase price	$	38,606

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

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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 bargain purchase gain is primarily attributable to the increase in crude oil price forecasts from the date the SPA was signed, November 17, 2020, to the closing date, February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

The actual impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statements of operations of $32.4 million and $9.4 million for the three months ended March 31, 2022 and March 31, 2021, respectively. The actual impact of the Sasol Acquisition was an increase to “Net income” in the condensed consolidated statements of operations of $5.7 million and $1.2 million for the three months ended March 31, 2022 and March 31, 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 months ended March 31, 2022, and March 31, 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.


	Three Months Ended March 31,
	2021
	(in thousands)
Pro forma (unaudited)
Crude oil and natural gas sales	$	57,547
Operating income		25,025
Net income		11,736	(a)

Basic net income loss per share:
Income from continuing operations	$	0.20
Net income per share	$	0.20
Basic weighted average shares outstanding		57,636
Diluted net income per share:
Income from continuing operations	$	0.20
Net income per share	$	0.20
Diluted weighted average shares outstanding		58,461

________________

(a)The pro forma net loss for the three months ended March 31, 2021 excludes nonrecurring pro forma adjustments directly attributable to the Sasol Acquisition, consisting of a bargain purchase gain of $7.7 million and transaction costs of $1.0 million.

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 months ended March 31, 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.

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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 months ended March 31, 2022 and 2021 as well as long-lived assets and segment assets at March 31, 2022 and December 31, 2021 are as follows:


	Three Months Ended March 31, 2022
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	68,656	$	—	$	—	$	68,656
Depreciation, depletion and amortization		4,653		—		20		4,673
Bad debt expense and other		492		—		—		492
Other operating expense, net		(5)		—		—		(5)
Operating income (loss)		44,705		(318)		(4,382)		40,005
Derivative instruments loss, net		—		—		(31,758)		(31,758)
Other, net		(638)		(1)		(57)		(696)
Income tax expense (benefit)		7,858		—		(12,486)		(4,628)
Additions to crude oil and natural gas properties and equipment – accrual		31,780		—		—		31,780



	Three Months Ended March 31, 2021
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	39,774	$	—	$	—	$	39,774
Depreciation, depletion and amortization		4,121		—		27		4,148
Operating loss		18,680		(132)		(4,205)		14,343
Derivative instruments gain, net		—		—		(5,954)		(5,954)
Other, net		7,681		(2)		(3,099)		4,580
Income tax expense		5,239		1		(2,154)		3,086
Additions to crude oil and natural gas properties and equipment – accrual⁽¹⁾		2,515		—		—		2,515

(1) Excludes assets acquired in the Sasol acquisition.



(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of March 31, 2022	$	111,787	$	10,000	$	148	$	121,935
As of December 31, 2021	$	84,156	$	10,000	$	168	$	94,324


(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Total assets from continuing operations:
As of March 31, 2022	$	235,229	$	10,871	$	62,410	$	308,510
As of December 31, 2021	$	201,748	$	10,548	$	50,794	$	263,090

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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”) 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 has been amended and extended several times, most recently in January 2022, to extend the date of the COSPA through the end of July 2022.

During the three months ended March 31, 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:


	Three Months Ended March 31,
		2022		2021
	(in thousands)
Net income (numerator):
Income from continuing operations	$	12,176	$	9,888
Income from continuing operations attributable to unvested shares		(140)		(187)
Numerator for basic		12,036		9,701
Income from continuing operations attributable to unvested shares		—		—
Numerator for dilutive	$	12,036	$	9,701

Loss from discontinued operations, net of tax	$	(12)	$	(19)
Income from discontinued operations attributable to unvested shares		—		—
Numerator for basic		(12)		(19)
Income from discontinued operations attributable to unvested shares		—		—
Numerator for dilutive	$	(12)	$	(19)

Net Income	$	12,164	$	9,869
Net income attributable to unvested shares		(139)		(187)
Numerator for basic		12,025		9,682
Net (income) loss attributable to unvested shares		—		—
Numerator for dilutive	$	12,025	$	9,682

Weighted average shares (denominator):
Basic weighted average shares outstanding		58,702		57,636
Effect of dilutive securities		477		825
Diluted weighted average shares outstanding		59,179		58,461
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		139		298

6. REVENUE

Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs. COSPAs 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.

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Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA. See Note 4 under “Information about the Company’s most significant customers” for further discussion.

COSPAs 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.

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, 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 $8.8 million foreign income tax payable as of March 31, 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.

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


	Three Months Ended March 31,
	2022		2021
Revenue from customer contracts:
Sales under the COSPA	$	76,486	$	43,829
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment		1,112		1,822
Royalties		(8,942)		(5,877)
Crude oil and natural gas sales	$	68,656	$	39,774

7. CRUDE OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT

The Company’s crude oil and natural gas properties and equipment is comprised of the following:



	As of March 31, 2022		As of December 31, 2021
	(in thousands)
Crude oil and natural gas properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	504,406	$	488,756
Work-in-progress		28,713		13,515
Undeveloped acreage		23,735		23,735
Equipment and other		24,410		23,478
		581,264		549,484
Accumulated depreciation, depletion, amortization and impairment		(459,329)		(455,160)
Net crude oil and natural gas properties, equipment and other	$	121,935	$	94,324

Extension of Term of Etame Marin Block PSC

On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Etame Consortium”), received an implementing Presidential Decree from the government of Gabon authorizing an extension for additional years (“PSC Extension”) to the Etame Consortium to operate in the Etame Marin block. The Company’s subsidiary, VAALCO Gabon S.A., currently has a 63.575% participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block. The PSC Extension extended the term for each of the three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17, 2018, the effective date of the PSC Extension, with two five-year options to extend the PSC.

In accordance with the Etame PSC, the Etame Consortium maintains a “Cost Account,” which accumulates capital costs and operating expenses that are deductible against revenues, net of royalties, in determining taxable profits. Under the PSC Extension, the Cost Recovery Percentage increased to 80% for the ten-year period from September 17, 2018 through September 16, 2028. After September 16, 2028, the Cost Recovery Percentage returns to 70%. The government of Gabon will acquire from the Etame Consortium an additional 2.5% gross working interest carried by the Etame Consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is 1.6%.

Proved Properties

The Company reviews the crude oil and natural gas producing properties for impairment quarterly or whenever events or changes in circumstances indicate that the carrying amount of such properties may not be recoverable. When a crude oil and natural gas property’s undiscounted estimated future net cash flows are not sufficient to recover its carrying amount, an impairment charge is recorded to reduce the carrying amount of the asset to its fair value. The fair value of the asset is measured using a discounted cash flow model relying primarily on Level 3 inputs into the undiscounted future net cash flows. The undiscounted estimated future net cash flows used in the impairment evaluations at each quarter end are based upon the most recently prepared independent reserve engineers’ report adjusted to use forecasted prices from the forward strip price curves near each quarter end and adjusted as necessary for drilling and production results.

There was no triggering event in the quarter ended March 31, 2022 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher forward price curves for the first quarter of 2022, and expected capital expenditures in the period related to the Etame Marin block.

Undeveloped Leasehold Costs

VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Ministry of Mines and Hydrocarbons (“EG MMH”) approved our appointment as operator for Block P on November 12, 2019. The

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Company acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing its working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million in the event that there is commercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. On April 12, 2021, the majority of non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties. As a result, VAALCO’s working interest will increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. As of March 31, 2022, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. The Company has completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P. VAALCO is now proceeding to a field development concept and will work closely with the other joint venture owners to complete this over the coming months. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

As a result of the PSC Extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame PSC. As a result of discovering reserves in connection with drilling the South East Etame 4H development well in March 2020, $2.3 million of costs were transferred to proved leasehold costs leaving a remaining $11.5 million in unproved leasehold costs. In connection with the Sasol Acquisition discussed under Note 3, $2.2 million of reserves were attributed to undeveloped properties. The balance of undeveloped leasehold costs related to the Etame Marin block at March 31, 2022 was $13.7 million.

Capitalized Equipment Inventory

Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating income (expense), net” line item of the condensed consolidated statements of operations but were not material for the three months ended March 31, 2022 and 2021.

8. DERIVATIVES AND FAIR VALUE

The Company uses derivative financial instruments from time to time to achieve a more predictable cash flow from crude oil production by reducing the Company’s exposure to price fluctuations.

On May 6, 2021, the Company entered into commodity swaps at a Dated Brent weighted average price of $66.51 per barrel for the period from and including May 2021 through October 2021 for a quantity of 672,533 barrels. On August 6, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $67.70 per barrel for the period from and including November 2021 through February 2022 for a quantity of 314,420 barrels. On September 24, 2021, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels. On January 6, 2022, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $76.53 per barrel for the period from and including July 2022 to September 2022 for a quantity of 375,000 barrels. On February 23, 2022, the Company entered into additional commodity swaps at a Dated Brent weighted average price of $85.01 per barrel for the period from and including April 2022 to June 2022 for a quantity of 234,000 barrels. See the table below for the unexpired barrels as of March 31, 2022.


Settlement Period	Type of Contract	Index	Barrels	Weighted Average Price
April 2022 to June 2022	Swaps	Dated Brent	345,000	$	72.00
April 2022 to June 2022	Swaps	Dated Brent	234,000	$	85.01
July 2022 to September 2022	Swaps	Dated Brent	375,000	$	76.53
			954,000

While these commodity swaps are intended to be an economic hedge to mitigate the impact of a decline in crude oil prices, the Company has not elected hedge accounting. The contracts are being measured at fair value each period, with changes in fair value recognized in net income. The Company does not enter into derivative instruments for speculative or trading proposes.

The crude oil swap contracts are measured at fair value using the Income Method. Level 2 observable inputs used in the valuation model include market information as of the reporting date, such as prevailing Brent crude futures prices, Brent crude futures commodity price volatility and interest rates. The determination of the swap contracts’ fair value includes the impact of the counterparty’s non-performance risk.

To mitigate counterparty risk, the Company enters into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.

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At times, the Company’s counterparties require that it post collateral for changes in the net fair value of the derivative contracts. This cash collateral is reported in the line item Restricted cash on the condensed consolidated balance sheets.

The following table sets forth the loss on derivative instruments on the Company’s condensed consolidated statements of operations:


		Three Months Ended March 31,
Derivative Item	Statement of Operations Line	2022		2021
		(in thousands)
Crude oil swaps	Cash settlements paid on matured derivative contracts, net	$	(12,500)	$	(1,710)
	Cash settlements not paid on matured derivative contracts, net		(19,258)		(4,244)
	Derivative instruments loss, net	$	(31,758)	$	(5,954)

9. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	As of March 31, 2022		As of December 31, 2021
	(in thousands)
Accrued accounts payable invoices	$	24,749	$	11,967
Gabon DMO, PID and PIH obligations		10,470		9,465
Derivative liability - crude oil swaps		24,064		4,806
Capital expenditures		20,568		11,327
Stock appreciation rights – current portion		1,422		609
Accrued wages and other compensation		939		2,124
ARO Obligation		6,790		6,745
Other		2,407		2,401
Total accrued liabilities and other	$	91,409	$	49,444

10. COMMITMENTS AND CONTINGENCIES

Abandonment funding

Under the terms of the Etame PSC, the Company has a cash funding arrangement for the eventual abandonment of all offshore wells, platforms and facilities on the Etame Marin block. As a result of the PSC Extension, annual funding payments are spread over the periods from 2018 through 2028, under the 2018 abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. In November 2021, an abandonment study was done and the estimate used for this purpose is approximately $81.3 million ($47.9 million, net to VAALCO) on an undiscounted basis. The abandonment estimate will be presented to the Gabonese Directorate of Hydrocarbons as required by the Etame PSC. Through March 31, 2022, $36.3 million ($21.4 million, net to VAALCO) on an undiscounted basis has been funded. The annual payments will be adjusted based on revisions in the abandonment estimate. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the 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.

On March 5, 2019, in accordance with certain foreign currency regulatory requirements, the Gabonese branch of an international commercial bank holding the abandonment funds in a U.S. dollar denominated account transferred the funds to the Central Bank for CEMAC, of which Gabon is one of the six member states. The U.S. dollars were converted to local currency with a credit back to the Gabonese branch. During the three months ended March 31, 2022, the Company recorded a $0.4 million foreign currency loss associated with the abandonment funding account. During the three months ended March 31, 2021, the Company recorded a $0.5 million foreign currency loss associated with the abandonment funding account. In December 2021, as part of the new FX regulations issued by BEAC, BEAC allowed for 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.

FPSO charter

In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for two one-year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. The Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. The Company’s net share of the charter payment is 58.8%, or approximately $19.4 million per year. Although the Company believes the need for

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performance under the charter guarantee is remote, the Company recorded a liability of $0.1 million as of March 31, 2022 and $0.1 million as of December 31, 2021 representing the guarantee’s estimated fair value. Estimated future minimum obligations as of March 31, 2022 through the end of the FPSO charter in September 2022 are approximately $15.9 million ($9.4 million, net to VAALCO).

The FPSO charter payment includes a $0.93 per barrel charter fee for production up to 20,000 barrels of crude oil per day and a $2.50 per barrel charter fee for those barrels produced in excess of 20,000 barrels of crude oil per day.

Regulatory and Joint Interest Audits and Related Matters

The Company is subject to periodic routine audits by various government agencies in Gabon, including audits of the Company’s petroleum cost account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under the Company’s joint operating agreements.

In 2016, the government of Gabon conducted an audit of the Company’s operations in Gabon, covering the years 2013 through 2014. The Company received the findings from this audit and responded to the audit findings in January 2017. Since providing the Company’s response, there have been changes in the Gabonese officials responsible for the audit. The Company is working with the newly appointed representatives to resolve the audit findings. The Company does not anticipate that the ultimate outcome of this audit will have a material effect on the Company’s financial condition, results of operations or liquidity.

Between 2019 and 2021, the government of Gabon conducted an audit of the operations in Gabon, covering the years 2015 and 2016. The Company has not yet received the findings from this audit.

In 2019, the Etame joint venture owners conducted audits for the years 2017 and 2018. In June 2020, the Company agreed to a $0.8 million payment to resolve claims made by one of the Etame Marin block joint venture owners, Addax Petroleum Gabon S.A. There are now no unresolved matters related to the joint venture owner audits for these years.

FSO

On August 31, 2021, VAALCO and its co-venturers at Etame approved the Bareboat Contract (the “Bareboat Contract”) and Operating Agreement (collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. to replace the existing FPSO with a Floating Storage and Offloading unit (“FSO”). The FSO Agreements require a prepayment of $2 million gross ($1.3 million net to VAALCO) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. Current total block level capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO). No other prepayments are required under the FSO Agreements until the vessel is accepted by the Company at the Etame Marin Block location. The FSO Agreements contain purchase provisions and termination provisions. The Company does not expect to utilize the terminations provision under the FSO Agreements. VAALCO currently believes that all of the associated engineering, long-lead equipment and significant contracts are proceeding in-line with the anticipated timelines and expected delivery schedules for the deployment of the FSO in the third quarter of 2022.

Dividend Policy

On November 3, 2021, the Company announced that the Company’s board of directors adopted a cash dividend policy of an expected $0.0325 per common share per quarter. On January 28, 2022, the Company announced that the Company’s board of directors had declared a quarterly cash dividend of $0.0325 per share of common stock, paid on March 18, 2022 to stockholders of record at the close of business on February 18, 2022. In April 2022, we declared our intent to pay a dividend of $0.0325 per share of common stock for the second quarter of 2022 ($0.13 annualized), which is payable June 24, 2022 to stockholders of record at the close of business on May 25, 2022. However, payment of future dividends, if any, will be at the discretion of the board of directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.

Other contractual commitments

In June 2021, the Company entered into a short-term agreement with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells. Upon completion of the ETBSM 1HB-ST2 well, the commitment to Borr Drilling Limited will be satisfied.

11. LEASES

Under the leasing standard that became effective January 1, 2019, there are two types of leases: finance and operating. Regardless of the type of lease, the initial measurement of the lease results in recording a ROU asset and a lease liability at the present value of the future lease payments.

Practical Expedients – The Company elected to use all the practical expedients, effectively carrying over its previous identification and classification of leases that existed as of January 1, 2019. Additionally, a lessee may elect not to recognize ROU assets and liabilities arising from short-term leases provided there is no purchase option the entity is likely to exercise. The Company has elected this short-term lease exemption.

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Operating leases

The Company is currently a party to several operating lease agreements for the corporate office, rental of marine vessels and helicopters, equipment and the FPSO. The duration for these agreements range from 3 to 36 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for the FPSO, the marine vessels, helicopter and certain equipment used in the joint operations includes the gross amount of the lease components.

During the third quarter of 2019, the Company notified the lessor of the FPSO of its intent to extend the lease term by the first option that extends the FPSO lease to September 2021. Similarly, during the third quarter of 2020, the Company gave notification to extend the FPSO lease to September 2022.

The FPSO agreement also contains options to purchase the assets during or at the end of the lease term. The Company does not consider these options reasonably certain of exercise and has excluded the purchase price from the calculation of ROU assets and lease liabilities.

The FPSO and helicopter, marine vessels and certain equipment leases include provisions for variable lease payments, under which the Company is required to make additional payments based on the level of production or the number of days or hours the asset is deployed, or the number of persons onboard the vessel. Because the Company does not know the extent that the Company will be required to make such payments, they are excluded from the calculation of ROU assets and lease liabilities.

Financing leases

In August 2021, the Company signed the FSO agreements to lease a FSO to replace the current FPSO whose term will end in September 2022. Under the terms of the FSO agreements, a third party is expected to modify the leased vessel in order to meet the Company’s crude-oil production requirements. The vessel is expected to arrive on location in the Etame Marin block in September 2022 at which time control of the vessel will transfer to the Company and at which time the Company will record the ROU asset and Lease liabilities associated with this lease.

On February 15, 2022, the Company signed a contract for a finance lease of generators and related parts. The minimum lease term is 67 months, and the ROU asset and lease liability was recorded on the lease commencement date of February 15, 2022.

All leases

For all leases that contain an option to extend, the Company has evaluated whether it will extend the lease beyond the initial lease term, which payments have been included in the calculation for the ROU assets and liabilities. The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.

For the three months ended March 31, 2022 and 2021, the components of the lease costs and the supplemental information were as follows:

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	Three Months Ended March 31,
	2022		2021
Lease cost:	(in thousands)
Finance lease cost ⁽¹⁾	$	66	$	—
Operating lease cost		4,196		4,390
Short-term lease cost ⁽²⁾		1,014		794
Variable lease cost ⁽³⁾		1,338		1,434
Total lease expense		6,614		6,618
Lease costs capitalized		772		—
Total lease costs	$	7,386	$	6,618

Other information:
Cash paid for amounts included in the measurement of lease liabilities:	2022		2021
Operating cash flows attributable to finance leases	$	—	$	—
Weighted-average remaining lease term		5.42 years		—
Weighted-average discount rate		3.54%		—

Operating cash flows attributable to operating leases	$	6,551	$	4,773
Weighted-average remaining lease term		0.73 years		1.5 years
Weighted-average discount rate		5.83%		6.09%

(1)Represents depreciation and interest associated with financing leases.

(2)Represents short term leases under contracts that are 1 year or less where a ROU asset and lease liability are not required to be recorded.

(3)Variable costs represent differences between minimum lease costs and actual lease costs incurred under lease contracts.

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The table below describes the presentation of the total lease cost on the Company’s condensed consolidated statement of operations. As discussed above, the Company’s joint venture owners are required to reimburse the Company for their share of certain expenses, including certain lease costs.


	Three Months Ended March 31,
	2022		2021
	(in thousands)
Finance lease cost	$	39	$	—
Production expense		3,838		2,649
General and administrative expense		16		49
Lease costs billed to the joint venture owners		3,002		3,920
Total lease expense		6,895		6,618
Lease costs capitalized		491		—
Total lease costs	$	7,386	$	6,618

The following table describes the future maturities of the Company’s lease liabilities at March 31, 2022:


	Operating Leases		Finance Leases
Year	(in thousands)
2022	$	6,397	$	311
2023		371		368
2024		197		368
2025		33		368
Thereafter		—		537
		6,998		1,952
Less: imputed interest		108		201
Total lease liabilities	$	6,890	$	1,751

Under the joint operating agreements, other joint venture owners are obligated to fund $5.3 million of the $9.0 million in future lease liabilities.

12. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in the Company’s asset retirement obligations:


(in thousands)	As of March 31, 2022		As of December 31, 2021
Beginning balance	$	40,694	$	17,334
Accretion		473		1,627
Additions		—		14,564
Revisions		—		7,169
Ending balance	$	41,167	$	40,694

Accretion is recorded in the line item “Depreciation, depletion and amortization” on the condensed consolidated statements of operations.

The Company is required under the Etame PSC for the Etame Marin block in Gabon to conduct abandonment studies to update the amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was prepared in November 2021. At December 31, 2021, associated with the study, the Company recorded an upward revision of $7.2 million to the asset retirement obligation primarily as a result of increased costs expected with the abandonment of the Etame Marin block and a change in the expected timing of the abandonment costs associated with the termination of the FPSO charter. As a result of the expected timing of the abandonment of the FPSO, included in accrued liabilities in the condensed consolidated balance sheet is $6.8 million of costs associated with the retirement obligation as of March 31, 2022.

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13. SHAREHOLDERS’ EQUITY

Preferred stock – Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. No shares of preferred stock were issued and outstanding as of March 31, 2022 or December 31, 2021.

Treasury stock – For the majority of restricted stock awards granted by the Company, the number of shares issued to the participant on the vesting date are net of shares withheld to meet applicable tax withholding requirements. In addition, when options are exercised, the participant may elect to remit shares to the Company to cover the tax liability and the cost of the exercised options. When this happens, the Company adds these shares to treasury stock and pays the taxes on the participant’s behalf.

Although these withheld shares are not issued or considered common stock repurchases under the Company’s stock repurchase program, they are treated as common stock repurchases in our financial statements as they reduce the number of shares that would have been issued upon vesting. See Note 14 for further discussion.

14. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s board of directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At March 31, 2022, 6,694,501 shares were available for future grants under the 2020 Plan.

For each stock option granted, the number of authorized shares under the 2020 Plan will be reduced on a one-for-one basis. For each restricted share granted, the number of shares authorized under the 2020 Plan will be reduced by twice the number of restricted shares. The Company has no set policy for sourcing shares for option grants. Historically the shares issued under option grants have been new shares.

As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the three months ended March 31, 2022, the Company settled in cash $0.2 million for stock appreciation rights and received $0.2 million for stock option exercises. During the three months ended March 31, 2021, the Company settled in cash $0.9 million for stock appreciation rights and received $0.3 million for stock option exercises


	Three Months Ended March 31,
	2022		2021
	(in thousands)
Stock-based compensation - equity awards	$	404	$	323
Stock-based compensation - liability awards		1,018		1,236
Total stock-based compensation	$	1,422	$	1,559

Stock options and performance shares

Stock options have an exercise price that may not be less than the fair market value of the underlying shares on the date of grant. In general, stock options granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s board of directors that is generally a three-year period, vesting in three equal parts on the anniversaries from the date of grant, and may contain performance hurdles.

In March 2022, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 241,358 shares at an exercise price of $6.41 per share and a life of ten years. For each performance stock option award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $7.37 per share; performance stock options with respect to one-third of the underlying shares vest on the later of the second anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $8.48 per share; and performance stock options with respect to the remaining one-third of the underlying shares vest on the later of the third anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $9.75 per share. These awards are option awards that contain a market condition. Compensation cost for such awards is recognized ratably over the derived service period and compensation cost related to awards with a market condition will not be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such performance criteria.

The Company used the Monte Carlo simulation to calculate the grant date fair value of performance stock option awards. The fair value of these awards will be amortized to expense over the derived service period of the option.

For options that do not contain a market or performance condition, the Company uses the Black-Scholes model to calculate the grant

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date fair value of stock option awards. This fair value is then amortized to expense over the service period of the option.

During the three months ended March 31, 2022 and 2021, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo.


	Three Months Ended March 31,
	2022			2021
Weighted average exercise price - ($/share)	$	6.41		$	3.14
Expected life in years		6.0			6.0
Average expected volatility		72	%		75	%
Risk-free interest rate		1.98	%		0.95	%
Expected dividend yield		2.30	%		—
Weighted average grant date fair value - ($/share)	$	2.84		$	2.07

Stock option activity associated with the Monte Carlo model for the three months ended March 31, 2022 is provided below:


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2022	359	$	1.96
Granted	241		6.41
Exercised	—		—
Unvested shares forfeited	—		—
Vested shares expired	—		—
Outstanding at March 31, 2022	600	$	3.75	9.09	$	1,670
Exercisable at March 31, 2022	120	$	1.96	8.51	$	547

Stock option activity associated with the Black-Scholes model for the three months ended March 31, 2022 is provided below:


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2022	615	$	1.58
Granted	—		—
Exercised	(171)		1.16
Unvested shares forfeited	—		—
Vested shares expired	—		—
Outstanding at March 31, 2022	444	$	1.74	1.49	$	2,125
Exercisable at March 31, 2022	429	$	1.73	1.47	$	2,062

During the three months ended March 31, 2022, 28,761 shares were added to treasury as a result of tax withholding on options exercised.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). In March 2022, the Company issued 353,424 shares of service-based restricted stock to employees, with a grant date fair value of $6.41 per share. The vesting of these shares is dependent upon, among other things, the employees’ and directors’ continued service with the Company.

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The following is a summary of activity for the three months ended March 31, 2022:


	Restricted Stock	Weighted Average Grant Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2022	741	$	2.36
Awards granted	353		6.41
Awards vested	(129)		3.07
Awards forfeited	(26)		3.06
Non-vested shares outstanding at March 31, 2022	939	$	3.77

During the three months ended March 31, 2022, 35,232 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.

Stock appreciation rights (“SARs”)

SARs may be granted under the VAALCO Energy, Inc. 2016 Stock Appreciation Rights Plan and the 2020 Plan. A SAR is the right to receive a cash amount equal to the spread with respect to a share of common stock upon the exercise of the SAR. The spread is the difference between the SAR exercise price per share specified in the SAR award (that may not be less than the fair market value of the Company’s common stock on the date of grant) and the fair market value per share of the Company’s common stock on the date of exercise of the SAR. SARs granted to participants will become exercisable over a period determined by the Compensation Committee of the Company’s board of directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s board of directors.

During the three months ended March 31, 2022, the Company did not grant SARs to employees or directors.

SAR activity for the three months ended March 31, 2022 is provided below:


	Number of Shares Underlying SARs	Weighted Average Exercise Price Per Share		Term	Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2022	362	$	1.81
Granted	—		—
Exercised	(59)		1.41
Unvested SARs forfeited	—		—
Vested SARs expired	—		—
Outstanding at March 31, 2022	303	$	1.89	1.75	$	1,402
Exercisable at March 31, 2022	237	$	1.94	1.65	$	1,086

Other Benefit Plans

The Company has adopted forms of change in control agreements for its named executive officers and certain other officers of the Company as well as a severance plan for its Houston-based non-executive employees in order to provide severance benefits in connection with a change in control. Upon a termination of a participant’s employment by the Company without cause or a resignation by the participant for good reason three months prior to a change in control or six months following a change in control, executives and officers with change in control agreements and participants in the severance plan will be entitled to receive 100% and 50%, respectively, of the participant’s base salary and continued participation in the Company’s group health plans for the participant and his or her eligible spouse and other dependents for six months. In addition, certain named executive officers will receive 75% of their target bonus. Some of the named executive officers are also entitled to severance payments under their employment agreements.

15. INCOME TAXES

VAALCO and its domestic subsidiaries file a consolidated U.S. income tax return. Certain foreign subsidiaries also file tax returns in their respective local jurisdictions.

Income taxes attributable to continuing operations for the three months ended March 31, 2022, and 2021 are attributable to foreign taxes payable in Gabon as well as income taxes in the U.S.

Provision for income taxes related to income from continuing operations consists of the following:

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	Three Months Ended March 31,
	2022		2021
U.S. Federal:	(in thousands)
Current	$	—	$	—
Deferred		(12,486)		(2,153)
Foreign:
Current		5,691		3,435
Deferred		2,167		1,804
Total	$	(4,628)	$	3,086

The Company’s effective tax rate for the three months ended March 31, 2022 and 2021, excluding the impact of discrete items, was 67.9% and (64%), respectively. For the three months ended March 31, 2022, the Company’s overall effective tax rate was impacted by non-deductible items associated with operations, and a change in valuation allowance. The total tax expense for the three months ended March 31, 2022 includes a discrete adjustment for the release of $12.7 million of valuation allowance as a result of an increase in forecasted future earnings. For the three months ended March 31, 2022, the current tax expense of $ 5.7 million includes a $3.1 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $2.6 million for the period. For the three months ended March 31, 2021, the current tax expense of $3.4 million includes a $0.5 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was produced and the time it was taken in-kind. After excluding the impact, current income taxes were $2.9 million for the period.

As of March 31, 2022, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.

‎

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Annual Report that address activities, events or developments that we expect or anticipate may occur in the future, including without limitation, statements regarding our financial position, operating performance and results, reserve quantities and net present values, market prices, business strategy, derivative activities, the amount and nature of capital expenditures, payment of dividends and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

the impact of the coronavirus (“COVID-19”) pandemic, including its impact on global demand for crude oil and crude oil prices, potential difficulties in obtaining additional liquidity when and if needed, disruptions in global supply chains, quarantines of our workforce or workforce reductions and other matters related to the pandemic;

the impact of any future production quotas imposed by Gabon, as a member of the Organization of the Petroleum Exporting Countries (“OPEC”), as a result of agreements among OPEC, Russia and other allied producing countries (collectively, “OPEC+”) with respect to crude oil production levels;

volatility of, and declines and weaknesses in crude oil and natural gas prices, as well as our ability to offset volatility in prices through the use of hedging transactions;

the discovery, acquisition, development and replacement of crude oil and natural gas reserves;

impairments in the value of our crude oil and natural gas assets;

future capital requirements;

our ability to maintain sufficient liquidity in order to fully implement our business plan;

our ability to generate cash flows that, along with our cash on hand, will be sufficient to support our operations and cash requirements;

the ability of the BWE Consortium of VAALCO, BW Energy and Panoro Energy to successfully execute its business plan;

our ability to attract capital or obtain debt financing arrangements;

our ability to pay the expenditures required in order to develop certain of our properties;

operating hazards inherent in the exploration for and production of crude oil and natural gas;

difficulties encountered during the exploration for and production of crude oil and natural gas;

the impact of competition;

our ability to identify and complete complementary opportunistic acquisitions;

our ability to effectively integrate assets and properties that we acquire into our operations;

weather conditions;

the uncertainty of estimates of crude oil and natural gas reserves;

currency exchange rates and regulations;

unanticipated issues and liabilities arising from non-compliance with environmental regulations;

the ultimate resolution of our abandonment funding obligations with the government of Gabon and the audit of our operations in Gabon currently being conducted by the government of Gabon;

the availability and cost of seismic, drilling and other equipment;

difficulties encountered in measuring, transporting and delivering crude oil to commercial markets;

our ability to effectively replace the floating, production, storage and offloading vessel (“FPSO”);

timing and amount of future production of crude oil and natural gas;

hedging decisions, including whether or not to enter into derivative financial instruments;

general economic conditions, including any future economic downturn, the impact of inflation, disruption in financial markets and the availability of credit;

our ability to enter into new customer contracts;

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changes in customer demand and producers’ supply;

actions by the governments of and events occurring in the countries in which we operate;

actions by our joint venture owners;

compliance with, or the effect of changes in, governmental regulations regarding our exploration, production, and well completion operations including those related to climate change;

the outcome of any governmental audit; and

actions of operators of our crude oil and natural gas properties.

The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2021 (“2021 Form 10-K”), identifies additional factors that could cause our results or performance to differ materially from those we express in forward-looking statements. Although we believe that the assumptions underlying our forward-looking statements are reasonable, any of these assumptions and therefore also the forward-looking statements based on these assumptions, could themselves prove to be inaccurate. In light of the significant uncertainties inherent in the forward-looking statements that are included in this Quarterly Report and the 2021 Form 10-K, our inclusion of this information is not a representation by us or any other person that our objectives and plans will be achieved. When you consider our forward-looking statements, you should keep in mind these risk factors and the other cautionary statements in this Quarterly Report.

Our forward-looking statements speak only as of the date the statements are made and reflect our best judgment about future events and trends based on the information currently available to us. Our results of operations can be affected by inaccurate assumptions we make or by risks and uncertainties known or unknown to us. Therefore, we cannot guarantee the accuracy of the forward-looking statements. Actual events and results of operations may vary materially from our current expectations and assumptions. Our forward-looking statements, express or implied, are expressly qualified in their entirety by this “Cautionary Statement Regarding Forward-Looking Statements,” which constitute cautionary statements. These cautionary statements should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances occurring after the date of this Quarterly Report.

INTRODUCTION

VAALCO is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, we have production operations and conduct exploration and development activities in Gabon, West Africa. We also have opportunities to participate in development and exploration activities in Equatorial Guinea, West Africa. As discussed further in Note 3 to the condensed consolidated financial statements included in this Quarterly Report, we have discontinued operations associated with our activities in Angola, West Africa.

RECENT DEVELOPMENTS

Marine Construction Agreement for Subsea Reconfiguration

On March 17, 2022, VAALCO Gabon, SA (“VAALCO Gabon”), a wholly owned subsidiary of the Company, entered into an Agreement for the Provision of Subsea Construction and Installation Services (the “Marine Construction Agreement”) with DOF Subsea Canada Corp. (“DOF Subsea”), to support the subsea reconfiguration in connection with the replacement of the existing FPSO vessel with a Floating Storage and Offloading vessel (“FSO”) at the Company’s Etame Marin field offshore Gabon. Pursuant to the Marine Construction Agreement, DOF Subsea agreed to, among other things, provide all personnel, crew and equipment necessary to assist in the reconfiguration of the Etame field subsea infrastructure to accommodate all field production to the flow to the FSO, which is currently under conversion, including (i) assistance with retrieval of over 5,000 meters of new flexible pipelines from a manufacturing facility in the United Kingdom, transporting the pipelines to Gabon and installing the pipelines in the Etame field, (ii) performing the retrieval and relocation of existing in-field flowlines and umbilicals to accommodate the reconfigured field development plan and (iii) assistance in the connection of new risers to the FSO (collectively, the “Services”). Pursuant to the Marine Construction Agreement, DOF Subsea will provide an offshore construction vessel to facilitate the performance of the Services. The Marine Construction Agreement provides that the Services will commence in early July 2022 and be completed by the end of September 2022, subject to certain conditions therein. As consideration for the Services provided to the Company, the Company agreed to pay DOF Subsea certain fixed fees upon the completion of the achievement of Service-related milestones, as well as a day rate, subject to certain conditions, as set forth in the Marine Construction Agreement.

Recent Operational Updates

Provisional Award of Two Offshore Blocks in Gabon

On October 11, 2021 we announced our entry into a consortium with BW Energy and Panoro Energy (the “BWE Consortium”) and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject

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

Charter Agreement for the Floating Storage and Offloading Unit

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

2021/2022 Drilling Campaign

In conjunction with the 2021/2022 drilling program, that began in December 2021, we executed a contract with Borr Jack-Up XIV Inc., an affiliate of Borr Drilling Limited, to drill a minimum of three wells with options to drill additional wells. On October 4, 2021, we novated the Borr Jack-Up XIV Inc contract with Borr West Africa Assets, Inc. In December of 2021, we spudded the Etame 8H sidetrack, the first well of the 2021/2022 drilling program. In February of 2022 we completed the drilling of the Etame 8-H well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST1 development well, which is targeting the Gamba reservoir. In April 2022, the well was completed and brought online in April with an IP rate of approximately 3,100 gross BOPD, 1,589 BOPD net to VAALCO’s 58.8% working interest in 2022.

VAALCO is currently drilling the ETBSM 1HB-ST2 well also on the Avouma platform and targeting the Gamba reservoir while also testing the Dentale formation, which is productive in other areas in the Etame license, with the potential to complete and produce from the Dentale in this well. We are currently planning to drill a fourth well following the ETBSM 1HB-ST2 well as part of its 2021/2022 drilling campaign.

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

Acquisition of Additional Working Interest at Etame Marin Block

In November 2020, we signed a SPA to acquire Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon. On February 25, 2021, we completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, we owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased our working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired have been included in our results for periods after February 25, 2021. All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items were recorded at their fair value. See Note 3 for further information.

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame Marin Block on behalf of a consortium of companies. As of March 31, 2022, production operations in the Etame Marin block included eleven platform wells, plus three subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the crude oil from a leased FPSO anchored to the seabed on the block. We currently have fourteen producing wells. The FPSO has production limitations of approximately 25,000 barrels of oil per day and 30,000 barrels of total fluids per day. During the three months ended March 31, 2022 and 2021, production from the block was 1,416 MBbls (725 MBbls net) and 1,253 MBbls (466 MBbls net), respectively, as discussed below in “Results of Operations”.

Equatorial Guinea

Our working interest will increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. As of March 31, 2022, we had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. We have completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P. We are now proceeding to a field development concept and will work closely with the other joint venture owners to complete this over the coming months. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

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DISCONTINUED OPERATIONS-ANGOLA

In November 2006, we signed a production sharing contract for Block 5 offshore Angola (“PSA”). Our working interest is 40%, and we carried Sonangol P&P, for 10% of the work program. On September 30, 2016, we notified Sonangol P&P that we were withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, we notified the national concessionaire, Sonangol E.P. that we were withdrawing from the PSA. Further to our decision to withdraw from Angola, we have closed our office in Angola and do not intend to conduct future activities in Angola. As a result of this strategic shift, the Angola segment has been classified as discontinued operations in the Financial Statements for all periods presented. See Note 3 to the Financial Statements. For the three months ended March 31, 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.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the three months ended March 31, 2022 and 2021 are as follows:


	Three Months Ended March 31,
	2022		2021		Increase (Decrease) in 2022 over 2021
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	26,407	$	13,453	$	12,954
Net change in operating assets and liabilities		(27,147)		(11,698)		(15,449)
Net cash (used in) provided by continuing operating activities		(740)		1,755		(2,495)
Net cash used in discontinued operating activities		(18)		(13)		(5)
Net cash (used in) provided by operating activities		(758)		1,742		(2,500)

Net cash used in investing activities		(23,148)		(19,056)		(4,092)

Net cash used in financing activities		(2,118)		(56)		(2,062)
Net change in cash, cash equivalents and restricted cash	$	(26,024)	$	(17,370)	$	(8,654)

The $13.0 million increase in net cash provided by our operating activities, before changes in operating assets and liabilities for the three months ended March 31, 2022 compared to the same period of 2021, was mainly due to positive contributions from adding back to cash the change in unrealized derivative losses. The net decrease in operating assets and liabilities of $15.4 million for the three months ended March 31, 2022 compared to the same period of 2021 was primarily related to an increase in assets of $25.5 million which was partially offset by a $10.1 million increase in liabilities.

The $4.1 million increase in net cash used in investing activities during the three months ended March 31, 2022 was due to increases in capital spending in 2022 for the Etame-8H development well and Etame field reconfiguration and other items to support the 2021/2022 drilling Campaign. For the three months ended March 31, 2021, cash used in investing activities was mainly due to cash used in the purchase of Sasol’s interest in the Etame Block.

Net cash used in financing activities during the three months ended March 31, 2022 included $1.9 million for dividend distribution, $0.4 million for treasury stock as a result of tax withholding on options exercised and vested restricted stock as discussed in Note 14 to our condensed consolidated financial statements, partially offset by $0.2 million in proceeds from options exercised.

Capital Expenditures

For the three months ended March 31, 2022 we had accrual basis capital expenditures attributable to continuing operations of $31.8 million compared to $2.5 million accrual basis capital expenditures in 2021, excluding the Sasol acquisition. For the three months ended March 31, 2022, our efforts were focused on spending related to the 2021/2022 drilling campaign and Etame field reconfigurations and FSO projects. During the same time in 2021, our spending was concentrated on the Sasol acquisition and obtaining certain long lead items for the 2021/2022 drilling campaign.

See table below in “Capital Resources, Liquidity and Cash Requirements” for further information.

Regulatory and Joint Interest Audits

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We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum Cost Account, customs, taxes and other operational matters, as well as audits by other members of the contractor group under our joint operating agreements. See Note 10 to the Financial Statements for further discussion.

Commodity Price Hedging

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

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

On September 24, 2021, we entered into additional commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels. On January 6, 2022, we entered into additional commodity swaps at a Dated Brent weighted average price of $76.53 per barrel for the period from and including July 2022 to September 2022 for a quantity of 375,000 barrels. On February 23, 2022, we entered into additional commodity swaps at a Dated Brent weighted average price of $85.01 per barrel for the period from and including April 2022 to June 2022 for a quantity of 234,000 barrels.

The following is a list of outstanding contracts at March 31, 2022:


Settlement Period	Type of Contract	Index	Barrels	Weighted Average Price
April 2022 to June 2022	Swaps	Dated Brent	345,000	$	72.00
April 2022 to June 2022	Swaps	Dated Brent	234,000	$	85.01
July 2022 to September 2022	Swaps	Dated Brent	375,000	$	76.53
			954,000

Cash on Hand

At March 31, 2022, we had unrestricted cash of $18.9 million. We invest cash not required for immediate operational and capital expenditure needs in short-term money market instruments primarily with financial institutions where we determine our credit exposure is negligible. As operator of the Etame Marin block in Gabon, we enter into project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from joint venture owners prior to significant funding commitments. Our cash on hand will be utilized, along with cash generated from operations, to fund our operations.

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

Capital Resources, Liquidity and Cash Requirements

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

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

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

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and whether to pursue growth opportunities and whether such growth opportunities, additional sources of liquidity, including equity and/or debt financings, are appropriate to fund any such growth opportunities.

Cash Requirements

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

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

FSO Agreements – We are currently a party to an FPSO charter for the production and storage of all of the crude oil that we produce. This contract will expire in September 2022. On August 31, 2021, we and our Etame co-venturers approved the Bareboat Contract and Operating Agreement with World Carrier to replace the existing FPSO with a FSO unit at the Etame Marin block offshore Gabon. Pursuant to the Bareboat Charter, World Carrier will provide use of the Cap Diamant vessel to VAALCO Gabon for an initial eight-year term, subject to optional two successive one-year extensions. Pursuant to the Operating Agreement, VAALCO Gabon agreed to engage World Carrier for the purposes of maintaining and operating the FSO on its behalf in accordance with the specifications therein and to provide other services to VAALCO Gabon in connection with the operation and maintenance of the FSO. As consideration for the performance by World Carrier of the Operator Services, VAALCO Gabon agreed to pay a daily operating fee (to be paid monthly) beginning on the date of issuance of the Fit to Receive Certificate (as defined in the Operating Agreement) until the end of the term, with such term being the same as the term in the Bareboat Charter.

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

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

BWE Consortium – On October 11, 2021 we announced our entry into a consortium with BW Energy and Panoro Energy and that the BWE Consortium has been provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of the PSC with the Gabonese government. BW Energy will be the operator with a 37.5% working interest. We will have a 37.5% working interest and Panoro Energy will have a 25% working interest as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively. The two blocks will be held by the BWE Consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by an additional two more years. During the first exploration period, the joint owners intend to reprocess existing seismic and carry out a 3-D seismic campaign on these two blocks and have also committed to drilling exploration wells on both blocks. In the event the BWE Consortium elects to enter the second exploration period, the BWE Consortium will be committed to drilling at least another one exploration well on each of the awarded blocks.

Drilling Program – We commenced the 2021/2022 drilling campaign in December 2021 with the drilling of the Etame 8-H development well. In February of 2022 we completed the drilling of the Etame 8-H well and moved the drilling rig to the Avouma platform to drill the Avouma 3H-ST1 development well, which is targeting the Gamba reservoir. The initial flow rate of the ETAME 8-H well was 5,000 BOPD, 2,560 BOPD net to VAALCO’s 58.8% working interest in 2022. In April 2022, the well was completed and brought online in April with an IP rate of approximately 3,100 gross BOPD, 1,589 BOPD net to VAALCO’s 58.8% working interest in 2022.

We expect the campaign to include two development wells and two appraisal wells at an estimated cost of $117.0 million to $143.0 million gross, or $74.0 million to $91.0 million, net to VAALCO’s 63.6% participating interest.

In June 2021, in conjunction with our 2021/2022 drilling program, we entered into a contract with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells. Upon completion of the ETBSM 1HB-ST2 well, the commitment to Borr Drilling Limited will be satisfied.

Dividend Policy – On November 3, 2021, we announced that our board of directors adopted of a quarterly cash dividend policy of an expected $0.0325 per common share commencing in the first quarter of 2022. We paid on March 18, 2022 a quarterly cash dividend of $1.9 million to the shareholders of record on February 18, 2022. Further we announced our intent to pay a dividend of $0.0325 per share of common stock for the second quarter of 2022 ($0.13 annualized), which is payable June 24, 2022 to stockholders of record at the close of business on May 25, 2022.

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

Trends and Uncertainties

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

Commodity Prices – Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our cash flows from operations may be adversely impacted by volatility in crude oil prices, a decrease in demand for crude oil and future production cuts by OPEC+. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. Brent crude prices were approximately $107 per barrel as of March 31, 2022. The decision to increase production was reaffirmed by an OPEC+ meeting held on March 31, 2022.

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

Hedging

We seek to mitigate the impact of volatility in crude oil prices through hedging. On September 24, 2021, we entered commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels. On January 6, 2022, we entered into additional commodity swaps at a Dated Brent weighted average price of $76.53 per barrel for the period from and including July 2022 to September 2022 for a quantity of 375,000 barrels. On February 23, 2022, we entered into additional commodity swaps at a Dated Brent weighted average price of $85.01 per barrel for the period from and including April 2022 to June 2022 for a quantity of 234,000 barrels.

See the table below for the unexpired barrels as of March 31, 2022:


Settlement Period	Type of Contract	Index	Barrels	Weighted Average Price
April 2022 to June 2022	Swaps	Dated Brent	345,000	$	72.00
April 2022 to June 2022	Swaps	Dated Brent	234,000	$	85.01
July 2022 to September 2022	Swaps	Dated Brent	375,000	$	76.53
			954,000

CRITICAL ACCOUNTING POLICIES

There have been no material changes to our critical accounting policies subsequent to December 31, 2021.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

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RESULTS OF OPERATIONS

Three Months Ended March 31, 2022 Compared to the Three Months Ended March 31, 2021

Net income for the three months ended March 31, 2022 was $12.2 million compared to net income of $9.9 million for the same period of 2021. See discussion below for changes in revenue and expense.

Crude oil and natural gas revenues increased $28.9 million, or approximately 72.6%, during the three months ended March 31, 2022 compared to the same period of 2021. The increase in revenue is attributable to higher sales prices and Sasol’s additional working interest for the full three months ended March 31, 2022.


	Three Months Ended March 31,
	2022		2021		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		616		619		(3)
Average crude oil sales price (per Bbl)	$	109.65	$	61.31	$	48.34

Net crude oil revenue	$	68,656	$	39,774	$	28,882

Operating costs and expenses:
Production expense		18,360		16,133		2,227
Exploration expense		127		142		(15)
Depreciation, depletion and amortization		4,673		4,148		525
General and administrative expense		4,994		4,547		447
Bad debt expense		492		101		391
Total operating costs and expenses		28,646		25,071		3,575
Other operating expense, net		(5)		(360)		355
Operating income	$	40,005	$	14,343	$	25,662

The revenue changes in the three months ended March 31, 2022 compared to the same period in 2021 identified as related to changes in price or volume, are shown in the table below:

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

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


	Three Months Ended March 31,
	2022		2021
Gabon net crude oil production (MBbls)		725		466
Gabon net crude oil sales (MBbls)		616		619

Average realized crude oil price ($/Bbl)	$	109.65	$	61.31
Average Dated Brent spot price* ($/Bbl)		100.87		61.04
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made two liftings during the three months ended March 31, 2022 and three liftings during the three months March 31, 2021. Although the number of barrels sold at March 31, 2022 is about the same as the numbers of barrels sold during March 31, 2021, the three months ended March 31, 2022 includes Sasol’s interest for the entire period while during the same period in 2021, Sasol’s interest was included after the acquisition date, February 25, 2021. Due to field start-up operational issues which pushed out the timing of third lifting until April 4, 2022, only two liftings occurred for the three months ended March 31, 2022. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 174,250 barrels and 53,858 barrels at March 31, 2022 and 2021, respectively.

Production expenses increased $2.2 million, or approximately 13.8%, for the three months ended March 31, 2022 compared to the same period in 2021. The increase in expense was primarily related to higher FPSO costs, boat expense, personnel, costs, and domestic market obligation (“DMO”) costs. On a per barrel basis, production expense, excluding workover expense, for the three months ended March 31, 2022 increased to $29.81 per barrel from $26.02 per barrel for the three months ended March 31, 2021 primarily as a result of lower

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sales volumes due to production interruptions in order to facilitate the 2021/2022 drilling campaign. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $0.9 million and $0.6 million in higher costs related to the proactive measures taken in response to the pandemic for each of the three months ended March 31, 2022 and 2021, respectively.

Depreciation, depletion and amortization costs increased $0.5 million, or approximately 12.7% due to the higher depletable base as a result of capital expenditures related to the 2021/2022 drilling program.

General and administrative expenses increased $0.4 million, or approximately 9.8% in the three months ended March 31, 2022 compared to the same period of 2021. The increase in expense was primarily related to increase on wages and salaries $0.4 million, professional and audit fees $0.5 million, offset by decrease legal fees $0.2 million and stock-based compensation $0.2 million.

Bad debt expense was higher between the three months ended March 31, 2022 and 2021 primarily due to 1) increased TVA balances as a result of increased interest in TVA balances and 2) increased TVA balances as a result of increased spend as a result of the 2021/2022 drilling campaign. The bad debt expense and related allowance account associated TVA balance has also increased as we have received no payments related to these balances in 2022.

Other operating income (expense), net for the three months ended March 31, 2022 and for the three months ended March 31, 2021 was not material to our results.

Derivative instruments loss, net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The $31.8 million and $6.0 million losses for the three months ended March 31, 2022 and 2021 are a result of the increase in the price of Dated Brent crude oil during the two periods. Every quarter in 2021 and continuing in 2022 Dated brent crude oil process have increased. Since the Company owes the counterparty for any Dated Brent price over the initial per barrel value and the Company continued to place on additional hedges in 2021 and 2022, the loss associated with the derivates have increased. Our derivative instruments currently cover a portion of our production through September 2022.

Other, net for the three months ended March 31, 2022 increased $5.4 million from an expense of $0.7 million for the three months ended March 31, 2022 compared to $4.6 million of income in the same period of 2021. For the three months ended March 31, 2022 Other, net primarily consists of foreign currency losses as discussed in Note 1 to the condensed consolidated financial statements. For the three months ended March 31, 2022, the $4.6 million of income in Other, net is primarily attributable to $7.7 million for the bargain purchase gain and expenses of $2.2 million for the difference in book to tax basis caused by the bargain purchase gain and $1.0 million for an acquisition success fee.

Income tax expense (benefit) for the three months ended March 31, 2022 was a benefit of $4.6 million. This is comprised of $12.5 million of deferred tax benefit and a current tax expense of $ (5.7) million. See Note 15 to the condensed consolidated financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices, foreign exchange rates and interest rates as described below.

Foreign Exchange Risk

Our results of operations and financial condition are affected by currency exchange rates. While crude oil sales are denominated in U.S. dollars, portions of our costs in Gabon are denominated in the local currency (the Central African CFA Franc, or XAF), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of March 31, 2022, we had net monetary assets of $11.1 million (XAF 6,525.3 million) denominated in XAF. A 10% weakening of the CFA relative to the U.S. dollar would have a $1.0 million reduction in the value of these net assets. For the three months ended March 31, 2022, we had expenditures of approximately $7.3 million denominated in XAF.

COUNTERPARTY Risk

We are exposed to market risk on our open derivative instruments related to potential nonperformance by our counterparty. To mitigate this risk, we enter into such derivative contracts with creditworthy financial institutions deemed by management as competent and competitive market makers.

Commodity Price Risk

Our major market risk exposure continues to be the prices received for our crude oil and natural gas production. Sales prices are primarily driven by the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and

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unpredictable in recent years, and this volatility may continue. Sustained low crude oil and natural gas prices or a resumption of the decreases in crude oil and natural gas prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If crude oil sales were to remain constant at the most recent quarterly sales volumes of 616 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.1 million decrease per quarter in revenues and operating income (loss) and a $2.8 million decrease per quarter in net income (loss).

As of March 31, 2022, we had unexpired derivative instruments outstanding covering 954 MBbls of production through September 2022. These instruments were intended to be an economic hedge against declines in crude oil prices; however, they were not designated as hedges for accounting purposes. See Note 8 to our condensed consolidated financial statements for further discussion.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

We performed an evaluation of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. The evaluation was performed with the participation of senior management, under the supervision of the principal executive officer and principal financial officer. Based on their evaluation as of March 31, 2022, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in internal control over financial reporting

There have been no changes in our internal control over financial reporting during the three months ended March 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. It is management’s opinion that none of the claims and litigation we are currently involved in are material to our business.

ITEM 1A. RISK FACTORS

Our business faces many risks. Any of the risks discussed elsewhere in this Quarterly Report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2021 Form 10-K. There have been no material changes in our risk factors from those described in our 2021 Form 10-K.

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ITEM 6. EXHIBITS

(a) Exhibits


3.1	Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014 and incorporated herein by reference).
3.2	Third Amended and Restated Bylaws (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 4, 2020 and incorporated herein by reference).
3.3	Certificate of Elimination of Series A Junior Participating Preferred Stock of VAALCO Energy, Inc., dated as of December 22, 2015 (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference).
10.1*	Amendment No. 1 to Employment Agreement, effective as of January 27, 2022, by and between VAALCO Energy, Inc. and George Maxwell (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 28, 2022 and incorporated herein by reference).
10.2*	Amendment No. 1 to Employment Agreement, effective as of January 27, 2022, by and between VAALCO Energy, Inc. and Ronald Bain (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on January 28, 2022 and incorporated herein by reference).
10.3(a)**	Agreement for the Provision of Subsea Construction and Installation Services, by and between VAALCO Gabon, SA and DOF Subsea Canada Corp., dated March 17, 2022.
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)	Inline XBRL Instance Document.
101.SCH(a)	Inline XBRL Taxonomy Schema Document.
101.CAL(a)	Inline XBRL Calculation Linkbase Document.
101.DEF(a)	Inline XBRL Definition Linkbase Document.
101.LAB(a)	Inline XBRL Label Linkbase Document.
101.PRE(a)	Inline XBRL Presentation Linkbase Document.
104	Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101).

(a) Filed herewith

(b) Furnished herewith

* Management contract or compensatory plan or arrangement.

** Information in this exhibit (indicated by asterisks) is confidential and has been omitted pursuant to Item 601(b)(10) of Regulation S-K. Additionally, exhibits and schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted exhibit or schedule will be furnished supplementally to the SEC or its staff upon request.

‎

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

VAALCO ENERGY, INC.

(Registrant)


By	:	/s/ Ronald Bain
		Ronald Bain
		Chief Financial Officer (Principal Financial Officer)

Dated: May 3, 2022

(in thousands)