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, ~~2021~~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, ~~2021,~~2022, there were outstanding ~~57,930,563~~58,902,069 shares of common stock, $0.10 par value per share, of the registrant.

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)



	As of March 31, 2021		As of December 31, 2020		As of March 31, 2022		As of December 31, 2021
ASSETS	(in thousands)				(in thousands)
Current assets:
Cash and cash equivalents	$	19,251	$	47,853	$	18,939	$	48,675
Restricted cash		82		86		4,230		79
Receivables:
Trade		23,803		—
Trade, net						44,616		22,464
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented		152		3,587		3,764		345
Other		29		4,331
Other, net						11,612		9,977
Crude oil inventory		820		3,906		4,634		1,593
Prepayments and other		5,175		4,215		8,408		5,156
Total current assets		49,312		63,978		96,203		88,289

Crude oil and natural gas properties, equipment and other - successful efforts method, net		78,192		37,036		121,935		94,324
Other noncurrent assets:
Restricted cash		1,752		925		1,752		1,752
Value added tax and other receivables, net of allowance of $5.1 million and $2.3 million, respectively		5,565		4,271
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		19,454		22,569		6,872		10,227
Right of use finance lease assets						1,795		—
Deferred tax assets						50,296		39,978
Abandonment funding		22,862		12,453		21,369		21,808
Other long-term assets						2,596		1,176
Total assets	$	177,137	$	141,232	$	308,510	$	263,090
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	10,121	$	16,690	$	10,509	$	18,797
Accounts with joint venture owners		1,721		4,945		—		3,233
Accrued liabilities and other		33,777		17,184		91,409		49,444
Operating lease liabilities - current portion		13,088		12,890		6,429		9,642
Finance lease liabilities - current portion						341		—
Foreign income taxes payable		6,384		860		8,819		3,128
Current liabilities - discontinued operations		13		7		7		13
Total current liabilities		65,104		52,576		117,514		84,257
Asset retirement obligations		32,196		17,334		34,377		33,949
Operating lease liabilities - net of current portion		6,361		9,671		461		587
Deferred tax liabilities		1,809		—
Other long-term liabilities		73		193
Finance lease liabilities - net of current portion						1,411		-
Total liabilities		105,543		79,774		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, 68,328,224 and 67,897,530 shares issued, 57,806,504 and 57,531,154 shares outstanding, respectively		6,833		6,790
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		75,064		74,437		77,272		76,700
Less treasury stock, 10,521,720 and 10,366,376 shares, respectively, at cost		(42,824)		(42,421)
Less treasury stock, 11,003,316 and 10,939,323 shares, respectively, at cost						(44,234)		(43,847)
Retained earnings		32,521		22,652		114,723		104,488
Total shareholders' equity		71,594		61,458		154,747		144,297
Total liabilities and shareholders' equity	$	177,137	$	141,232	$	308,510	$	263,090

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
	(in thousands, except per share amounts)				(in thousands, except per share amounts)
Revenues:
Crude oil and natural gas sales	$	39,774	$	18,389	$	68,656	$	39,774
Operating costs and expenses:
Production expense		16,133		9,749		18,360		16,133
Exploration expense		142		—		127		142
Depreciation, depletion and amortization		4,148		3,103		4,673		4,148
Impairment of proved crude oil and natural gas properties		—		30,625
General and administrative expense		4,547		754		4,994		4,547
Bad debt expense and other		101		810		492		101
Total operating costs and expenses		25,071		45,041		28,646		25,071
Other operating expense, net		(360)		(31)		(5)		(360)
Operating income (loss)		14,343		(26,683)
Operating income						40,005		14,343
Other income (expense):
Derivative instruments gain (loss), net		(5,954)		7,339
Interest income, net		5		116
Other, net		4,580		(31)
Total other income (expense), net		(1,369)		7,424
Income (loss) from continuing operations before income taxes		12,974		(19,259)
Income tax expense		3,086		33,478
Income (loss) from continuing operations		9,888		(52,737)
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		(19)		(63)		—		—
Net income (loss)	$	9,869	$	(52,800)

Basic net income (loss) per share:
Income (loss) from continuing operations	$	0.17	$	(0.91)
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		0.00		0.00		—		—
Net income (loss) per share	$	0.17	$	(0.91)
Basic weighted average shares outstanding		57,636		57,975
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	0.17	$	(0.91)
Loss from discontinued operations, net of tax		0.00		0.00
Net income (loss) per share	$	0.17	$	(0.91)
Net income per share					$	0.20	$	0.17
Diluted weighted average shares outstanding		58,461		57,975		59,179		58,461

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

Common Shares Issued
Treasury Shares
Common Stock
Additional Paid-In Capital
Treasury Stock
Retained Earnings
Total
(in thousands)
Balance at January 1, 2020
67,674
(9,649)
$
6,767
$
73,549
$
(41,429)
$
70,833
$
109,720
Shares issued - stock-based compensation
125
—
13
(13)
—
—
—
Stock-based compensation expense
—
—
—
145
—
—
145
Treasury stock
—
(517)
—
—
(652)
—
(652)
Net loss
—
—
—
—
—
(52,800)
(52,800)
Balance at March 31, 2020
67,799
(10,166)
$
6,780
$
73,681
$
(42,081)
$
18,033
$
56,413

See notes to condensed consolidated financial statements.
‎

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
	(in thousands)				(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	9,869	$	(52,800)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations		19		63
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		4,148		3,103		4,673		4,148
Bargain purchase gain		(7,651)		—		—		(7,651)
Impairment of proved crude oil and natural gas properties		—		30,625
Other amortization		—		60
Deferred taxes		1,809		35,638		(10,318)		1,809
Unrealized foreign exchange gain		(400)		(22)
Unrealized foreign exchange loss (gain)						116		(400)
Stock-based compensation		1,559		(2,569)		1,422		1,559
Cash settlements paid on exercised stock appreciation rights		(852)		—		(205)		(852)
Derivative instruments (gain) loss, net		5,954		(7,339)
Cash settlements received (paid) on matured derivative contracts, net		(1,710)		718
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		101		810		492		101
Other operating loss, net		360		31
Other operating expense, net						5		360
Operational expenses associated with equipment and other		247		578		240		247
Cash advance for other long-term assets						(1,452)		—
Change in operating assets and liabilities:
Trade receivables		(12,647)		14,335		(22,152)		(12,647)
Accounts with joint venture owners		275		13,812		(6,652)		275
Other receivables		(53)		(755)		(1,723)		(53)
Crude oil inventory		5,795		(2,793)		(3,041)		5,795
Prepayments and other		(3,240)		(993)		(876)		(3,240)
Value added tax and other receivables		(149)		(370)		(1,076)		(149)
Accounts payable		(6,627)		(1,130)		(10,132)		(6,627)
Foreign income taxes receivable/payable		5,524		(1,284)		5,691		5,524
Accrued liabilities and other		(576)		(2,073)		12,814		(576)
Net cash provided by continuing operating activities		1,755		27,645
Net cash (used in) provided by continuing operating activities						(740)		1,755
Net cash used in discontinued operating activities		(13)		(18)		(18)		(13)
Net cash provided by operating activities		1,742		27,627
Net cash (used in) provided by operating activities						(758)		1,742
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(1,198)		(11,980)		(23,148)		(1,198)
Acquisition of crude oil and natural gas properties		(17,858)		—		—		(17,858)
Net cash used in continuing investing activities		(19,056)		(11,980)		(23,148)		(19,056)
Net cash used in discontinued investing activities		—		—		—		—
Net cash used in investing activities		(19,056)		(11,980)		(23,148)		(19,056)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		347		—		198		347
Dividend distribution						(1,929)		—
Treasury shares		(403)		(652)		(387)		(403)
Net cash used in continuing financing activities		(56)		(652)		(2,118)		(56)
Net cash used in discontinued financing activities		—		—		—		—
Net cash used in financing activities		(56)		(652)		(2,118)		(56)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(17,370)		14,995		(26,024)		(17,370)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		61,317		59,124		72,314		61,317
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	43,947	$	74,119	$	46,290	$	43,947

VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND ACCOUNTINGPOLICIES

VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, ~~“VAALCO,”~~“VAALCO” or the “Company”) is a Houston, ~~Texas based~~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, ~~the Company~~VAALCO has discontinued operations associated with activities in Angola, West Africa.

~~VAALCO’s~~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, ~~2020,~~2021, which includes a summary of the significant accounting policies.

With respect to the novel strain of coronavirus (“COVID-19”), ~~a global pandemic was declared by the World Health Organization on March 11, 2020. As a result~~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 ~~pandemic, many companies~~uncertainty and instability in the industry. COVID-19 related travel restrictions have ~~experienced disruptions in their operations~~gradually eased as governments and ~~in markets served. The Company has instituted some and may take additional temporary precautionary measures intended~~people continue to have increasing access to vaccines that help ~~ensure~~reduce the ~~well-being~~spread of ~~its employees and minimize business disruption. Such measures include social distancing measures and actively screening and monitoring employees and contractors that come on~~COVID-19. Further there are indicators of improving economic activity to pre-COVID-19 levels while managing the ~~Company’s facilities. The adverse economic effects~~risk of ~~the COVID-19 outbreak have materially decreased demand for crude oil based on the restrictions in place by governments trying to curb the outbreak and changes in consumer behavior. This has led to~~ a ~~significant global oversupply of crude oil and consequently a substantial decrease in crude oil prices.~~

resurgence.

In ~~response~~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 ~~oversupply of~~three months ended March 31, 2022, the average brent crude oil ~~global~~price was over $100 per barrel. The average brent crude oil producers, including the Organization of Petroleum Exporting Countries and other oil producing nations (“OPEC+”), reached agreement in April 2020 to cut crude oil production. Further, in connection with the OPEC+ agreement, the Minister of Hydrocarbons in Gabon requested that the Company reduce its production. In response to such request from the Minister of Hydrocarbons, beginning in July 2020 and continuing through June 30, 2021, the Company has temporarily reduced production from the Etame Marin block.

~~The Company considered the impact of the COVID-19 pandemic and the substantial decline in crude oil prices on the assumptions and estimates used~~price for ~~preparation of the financial statements. As a result, the Company recognized a number of material charges during~~ the three months ended March 31, ~~2020, including impairments~~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 capitalized costs for proved crude oil and natural gas properties and valuation allowances on its deferred tax assets. These are discussed further in the following notes. Crude oil prices improved by March 31, 2021, and therefore 0 additional charges or impairments were required in the three months ended March 31, 2021. The full extent of the future impactsoperations as a result of COVID-19 ~~on the Company’s operations is uncertain. A prolonged~~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, ~~2021~~2022 and ~~2020~~2021 each include an escrow amount ~~representing bank guarantees for customs clearance in Gabon. Long- term amounts at March 31, 2021 and 2020 include a charter payment escrow~~ 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.~~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 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” inon 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 1210 for further discussion.

On February 28, 2019, the Gabonese branch of anthe international commercial bank holding the abandonment funds in a U.S. dollar denominated account advised that the bank regulator required transfer of the funds to the Central Bank (“Central Bank”) for ~~the~~African Economic and Monetary Community ~~of Central Africa~~ (“CEMAC”), of which Gabon is one of the six member states, for conversion to local currency with a credit back to the Gabonese branch in local currency. The Company’s production sharing contract related to the Etame Marin block located offshore Gabon (“Etame ~~Marin block~~ PSC”) provides ~~that~~ these payments must be denominated in U.S. ~~dollars. The new~~dollars and the CEMAC ~~foreign currency~~ regulations provide for the establishment of a U.S. dollar account with the Central Bank. Although wethe Company requested establishment of such account, the Central Bank did not comply with ~~our~~its requests until February 2021. As a result, ~~we were~~the Company was not able to make the annual abandonment funding ~~payment~~payments in 2019, ~~and 2020.~~2020 or 2021 totaling $4.3 million, net to VAALCO based on the 2018 abandonment study. In February of 2021, the Bank of Central ~~Bank~~African State (“BEAC”) authorized the Company to apply for a ~~USD~~U.S. dollar denominated escrow account for the ~~Abandonment Fund~~abandonment fund at Citibank ~~Gabon.~~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 ~~Citibank~~the extractive industry to ~~complete~~formulate the ~~documentation requires for the account.~~agreements, which are expected to be finalized in 2022, that regulate these accounts. Accordingly, pursuant to Amendment No. 5 toof the Etame ~~Marin block~~ PSC ~~also provides~~ that required these funds to be in U.S. dollars, once the ~~event that~~account for the ~~Gabonese bank fails for any reason to reimburse all~~U.S. dollars abandonment fund is open at BEAC we will resume our funding of the ~~principal~~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 ~~interest due,~~production expenditures made by the Company ~~and other joint interest owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.~~

Accounts Receivable and Allowance for Doubtful Accounts – The Company’s accounts receivable results from sales of crude oil production, ~~and~~ joint interest billings to its joint interest owners for their share of expenses on joint venture projects for which the Company is the operator, ~~as well as~~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~~.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 ~~$12.9~~$14.5 million ($~~8.8~~9.6 million, net to VAALCO). As of ~~March~~December 31, 2021, the exchange rate was XAF ~~559.3~~578.2 = $1.00. ~~As of December 31, 2020, the exchange rate was XAF~~ ~~534.8~~ ~~= $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.

~~Derivative Instruments~~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 ~~Hedging Activities~~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 andrepresent 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 ~~enters into~~ uses the successful efforts method of accounting for crude oil ~~hedging arrangements from~~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 ~~time~~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 ~~effort~~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 ~~mitigate~~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 ~~effects~~estimated useful lives of ~~commodity price volatility~~the assets, which are typically five years for office and ~~enhance~~miscellaneous equipment and five to seven years for leasehold improvements.

Impairment– The Company reviews the ~~predictability~~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 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~~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 ~~derivative instruments and~~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 ~~settlements on commodity derivatives are presented~~flows. The fair value measurement used in the ~~“Derivative instruments gain (loss), net” line item located within~~impairment test is generally calculated with a discounted cash flow model using several Level 3 inputs that are based upon estimates the ~~“Other income (expense)” section~~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 ~~condensed consolidated statements~~quality of ~~operations.~~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 87 for further discussion.

~~Fair Value~~Purchase Accounting – ~~Fair value is defined as~~On February 25, 2021, VAALCO Gabon S.A., a wholly owned subsidiary of the ~~price that would be received~~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 ~~sell an asset or~~ the ~~price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Inputs used~~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 ~~are characterized according~~models with the assistance of outside consultants. These fair value models were used to ~~a hierarchy that prioritizes those inputs~~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 ~~degree~~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 ~~which they are observable. The three input levels~~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 ~~fair-value hierarchy are as follows:~~

~~Level 1 – Inputs represent quoted prices~~type of lease, the initial measurement of the lease results 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~~recording a right of use (“ROU”) asset and a lease liability at the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

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

~~Fair value of financial instruments~~ – The Company’s assets and liabilities include financial instruments such as cash and cash equivalents, restricted cash, accounts receivable, derivative assets, accounts payable, SARs and guarantees. As discussed above, derivative assets and liabilities are measured and reported at fair value each period with changes in fair value recognized in net income. With respect to the Company’s other financial instruments included in current assets and liabilities, the carrying value of each financial instrument approximates fair value primarily due to the short-term maturity of these instruments. There were 0 transfers between levels for the three months ended March 31, 2021 and 2020.

As of March 31, 2021
Balance Sheet Line
Level 1
Level 2
Level 3
Total
(in thousands)
Liabilities
SARs liability
Accrued liabilities
$
—
$
2,792
$
—
$
2,792
Derivative liability - crude oil swaps
Accrued liabilities
—
4,244
—
4,244
Contingent payment
Accrued liabilities
—
5,000
—
5,000
SARs liability
Other long-term liabilities
—
73
—
73
$
—
$
12,109
$
—
$
12,109
As of December 31, 2020
Balance Sheet Line
Level 1
Level 2
Level 3
Total
(in thousands)
Liabilities
SARs liability
Accrued liabilities
$
—
$
2,289
$
—
$
2,289
SARs liability
Other long-term liabilities
—
193
—
193
$
—
$
2,482
$
—
$
2,482

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

~~Capitalization~~ – Costs of successful wells, development dry holes and leases containing productive reserves are capitalized and amortized on a unit-of-production basis over the life of the related reserves. Other exploration costs, including dry exploration well costs, geological and geophysical expenses applicable to undeveloped leaseholds, leasehold expiration costs and delay rentals, are expensed as incurred. The costs of exploratory wells are initially capitalized pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. Cost incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized if (i) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (ii) sufficient progress in assessing the reserves and the economic and operating viability of the project has been made. The status of suspended well costs is monitored continuously and reviewed quarterly. Due to the capital-intensive nature and the geographical characteristics of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination of its commercial viability. Geological and geophysical costs are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining development well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense.

~~Depreciation, depletion and amortization~~ – Depletion of wells, platforms, and other production facilities are calculated on a field-by-field basis under the unit-of-production method based upon estimates of proved developed reserves. Depletion of developed leasehold acquisition costs are provided on a field-by-field 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.~~

~~Impairment– The Company reviews the crude oil and natural gas producing properties for impairment~~ ~~on a field-by-field 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 a field contains lower than anticipated reserves or if commodity prices fall below a level that significantly effects anticipated future cash flows on the field. 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.

~~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”). See Note 3 for further discussion. 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 reserve 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. 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 Company’s condensed consolidated statement of operations. An income tax benefit of $2.2 million, related to the bargain purchase gain, is also included in the condensed consolidated statement of operations. The reason for the bargain purchase gain is mainly due to the lower oil price outlook used when the SPA was signed on November 17, 2020, and the higher oil price outlook on the closing date, February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

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

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

A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the crude oil and natural gas properties. The Company uses 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 is adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of the capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil and natural gas production facilities, while accretion escalates over the lives of the assets to reach the settlement value. See Note 12 for disclosures regarding the asset retirement obligations. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain.

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

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).

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.

~~Adopted~~

~~In December 2019, the~~ ~~Financial Accounting Standards Board (“FASB”)~~ ~~issued ASU No. 2019-12,~~ ~~Income Taxes (Topic 740: Simplifying the Accounting for Income Taxes~~ (“ASU 2019-12”), which removes certain exceptions to the general principles in Topic 740. ASU 2019-12 is effective for the fiscal years beginning after December 15, 2020, with early adoption permitted. ~~The adoption of this guidance did not have a material impact on the Company's financial statements.~~

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%~~, almost doubling the Company’s total production and reserves.~~. 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 ~~preliminary~~ allocation of the purchase price to the assets acquired and liabilities assumed in the Sasol Acquisition. The final determination of fair value for certain assets and liabilities will be completed as soon as the information necessary to complete the analysis is obtained. These amounts will be finalized as soon as possible, but no later than one year from the date of the acquisition. The final determination of fair value for certain assets and liabilities (VAT and accrued liabilities) could differ materially from the amounts set forth below


		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		~~(10,122)~~(10,121)
Bargain purchase gain		~~(7,650)~~(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

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 ~~“Total revenues”~~“Crude oil and natural gas sales” in the condensed consolidated ~~statement~~statements of operations of $32.4 million and $9.4 million for the three months ended March 31, 2022 and March 31, 2021, ~~and a $1.2 million~~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, ~~2021.~~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, ~~and 2020,~~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 of 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
2020
(in thousands)
Pro forma (unaudited)
Crude oil and natural gas sales
$
57,547
$
34,820
Operating income (loss)
25,025
(21,501)
Net income (loss)
11,736
(a)
(47,155)
(b)
Basic net income (loss) per share:
Income (loss) from continuing operations
$
0.20
$
(0.81)
Loss from discontinued operations, net of tax
0.00
0.00
Net income (loss) per share
$
0.20
$
(0.81)
Basic weighted average shares outstanding
57,636
57,975
Diluted net income (loss) per share:
Income (loss) from continuing operations
$
0.20
$
(0.81)
Loss from discontinued operations, net of tax
0.00
0.00
Net income (loss) per share
$
0.20
$
(0.81)
Diluted weighted average shares outstanding
58,461
57,975


	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.

~~(b)~~The pro forma net loss for the three months ended March 31, 2020 includes 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 iswas 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. As of March 31, 2021, the Company estimated the liability associated with this payment to be $5.0 million and recorded the difference between the initial fair value and the fair value at March 31, 2021 as additional expense ~~included in~~ “~~Other operating expense, net” in the condensed consolidated statements of operations.~~ ~~On April 29, 2021, the~~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, ~~2021~~2022 and ~~2020~~2021, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

4. SEGMENT INFORMATION

The Company’s operations are based in Gabon and the Company has an undeveloped block in Equatorial Guinea. Each of the Company’s 2 reportable operating segments is organized and managed based upon geographic location. TheThe 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, ~~2021~~2022 and ~~2020~~2021 as well as long-lived assets and segment assets at March 31, ~~2021~~2022 and December 31, ~~2020~~2021 are as follows:


	Three Months Ended March 31, 2021								Three Months Ended March 31, 2022
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total		Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	39,774	$	—	$	—	$	39,774	$	68,656	$	—	$	—	$	68,656
Depreciation, depletion and amortization		4,121		—		27		4,148		4,653		—		20		4,673
Bad debt expense and other										492		—		—		492
Other operating expense, net										(5)		—		—		(5)
Operating income (loss)		18,680		(132)		(4,205)		14,343		44,705		(318)		(4,382)		40,005
Derivative instruments gain, net		—		—		(5,954)		(5,954)
Derivative instruments loss, net										—		—		(31,758)		(31,758)
Other, net		7,681		(2)		(3,099)		4,580		(638)		(1)		(57)		(696)
Income tax expense (benefit)		5,239		1		(2,154)		3,086		7,858		—		(12,486)		(4,628)
Additions to crude oil and natural gas properties and equipment – accrual		2,515		—		—		2,515		31,780		—		—		31,780



	Three Months Ended March 31, 2020								Three Months Ended March 31, 2021
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total		Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	18,389	$	—	$	—	$	18,389	$	39,774	$	—	$	—	$	39,774
Depreciation, depletion and amortization		3,072		—		31		3,103		4,121		—		27		4,148
Impairment of proved crude oil and natural gas properties		30,625		—		—		30,625
Bad debt expense and other		810		—		—		810
Operating loss		(26,283)		(125)		(275)		(26,683)		18,680		(132)		(4,205)		14,343
Derivative instruments loss, net		—		—		7,339		7,339
Derivative instruments gain, net										—		—		(5,954)		(5,954)
Other, net										7,681		(2)		(3,099)		4,580
Income tax expense		22,039		—		11,439		33,478		5,239		1		(2,154)		3,086
Additions to crude oil and natural gas properties and equipment – accrual(1)		9,421		—		—		9,421		2,515		—		—		2,515

(in thousands)
Gabon
Equatorial Guinea
Corporate and Other
Total
Long-lived assets from continuing operations:
As of March 31, 2021
$
68,016
$
10,000
$
176
$
78,192
As of December 31, 2020
$
26,832
$
10,000
$
204
$
37,036


(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

The Company currently sells crude oil production from Gabon under term ~~contracts~~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. ~~From February 2019 to January 2020, crude oil sales were to Mercuria Energy Trading SA (“Mercuria”).~~ The Company signed a ~~new contract~~COSPA with ExxonMobil Sales and Supply LLC (“Exxon”) that ~~covers~~covered sales from February 2020 through ~~July 2021~~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,				Three Months Ended March 31,
		2021		2020		2022		2021
	(in thousands)				(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	9,888	$	(52,737)
Net income (numerator):
Income from continuing operations					$	12,176	$	9,888
Income from continuing operations attributable to unvested shares		(187)		—		(140)		(187)
Numerator for basic		9,701		(52,737)		12,036		9,701
(Income) loss from continuing operations attributable to unvested shares		—		—
Income from continuing operations attributable to unvested shares						—		—
Numerator for dilutive	$	9,701	$	(52,737)	$	12,036	$	9,701

Loss from discontinued operations, net of tax	$	(19)	$	(63)	$	(12)	$	(19)
(Income) loss from discontinued operations attributable to unvested shares		—		—
Income from discontinued operations attributable to unvested shares						—		—
Numerator for basic		(19)		(63)		(12)		(19)
(Income) loss from discontinued operations attributable to unvested shares		—		—
Income from discontinued operations attributable to unvested shares						—		—
Numerator for dilutive	$	(19)	$	(63)	$	(12)	$	(19)

Net income (loss)	$	9,869	$	(52,800)
Net Income					$	12,164	$	9,869
Net income attributable to unvested shares		(187)		—		(139)		(187)
Numerator for basic		9,682		(52,800)		12,025		9,682
Net (income) loss attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	9,682	$	(52,800)	$	12,025	$	9,682

Weighted average shares (denominator):
Basic weighted average shares outstanding		57,636		57,975		58,702		57,636
Effect of dilutive securities		825		—		477		825
Diluted weighted average shares outstanding		58,461		57,975		59,179		58,461
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		298		725		139		298

Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs. ~~The~~ COSPAs ~~have been~~with customers are renegotiated near the end of the contract term and ~~will~~may be ~~renewed~~entered into with a different customer or ~~replaced from time to time either~~the same customer going forward.

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, 2021		As of December 31, 2020		As of March 31, 2022		As of December 31, 2021
	(in thousands)				(in thousands)
Crude oil and natural gas properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	477,477	$	441,879	$	504,406	$	488,756
Work-in-progress		542		169		28,713		13,515
Undeveloped acreage		23,735		21,476		23,735		23,735
Equipment and other		16,016		9,276		24,410		23,478
		517,770		472,800		581,264		549,484
Accumulated depreciation, depletion, amortization and impairment		(439,578)		(435,764)		(459,329)		(455,160)
Net crude oil and natural gas properties, equipment and other	$	78,192	$	37,036	$	121,935	$	94,324

On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the ~~“Consortium”~~“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 3 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. The PSC~~ Extension, ~~also granted the Consortium the right for~~with 2 ~~additional extension periods of five years each. The PSC Extension further allows the Consortium~~five-year options to ~~explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in~~extend the PSC ~~Extension.~~

In consideration for the PSC Extension, the Consortium agreed to a signing bonus of $65.0 million ($21.8 million, net to VAALCO) payable to the government of Gabon (the “signing bonus”). The Consortium paid $35.0 million ($11.8 million, net to VAALCO) in cash on September 26, 2018 and paid $25.0 million ($8.4 million, net to VAALCO) through an agreed upon reduction of the VAT receivable owed by the government of Gabon to the Consortium as of the effective date. An additional $5.0 million ($1.7 million, net to VAALCO) was paid in cash in February 2020 by the Consortium following the end of the drilling activities described below.

As required under the PSC Extension, the Consortium completed drilling 2 development wells and 2 appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. During September 2020, the Consortium completed the 2 technical studies at a cost of $1.5 million gross ($0.5 million, net to VAALCO).

In accordance with the Etame ~~Marin block~~ 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%.

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 ~~first~~ quarter ~~of 2021~~ended March 31, 2022 that would cause usthe Company to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher ~~future strip prices~~forward price curves for the first quarter of ~~2021 compared~~

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.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. ~~VAALCO is seeking to farm down its interest in Block P in exchange for funding a substantial portion of an appraisal well.~~ 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, ~~2021~~,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 ~~its current and potential future~~will work closely with the other joint venture owners ~~are evaluating~~to complete this over the ~~timing and budgeting for development and exploration activities under a development and production area in the block, including the approval of a development and production plan.~~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 ~~Marin block~~ 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, ~~2021~~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~~“Other operating ~~expense, net”~~income (expense), net” line item of the condensed consolidated statements of operations but were not material for the three months ended March 31, ~~2021~~2022 and ~~2020.~~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.

~~Commodity swaps~~ – On May 6, 2019, the Company entered into commodity swaps at a Dated Brent weighted average of $66.70 per barrel for the period from and including July 2019 through June 2020 for an approximate quantity of 500,000 barrels. On January 22, 2021, the Company entered into commodity swaps at a Dated Brent weighted average of $53.10 per barrel for the period from and including February 2021 through January 2022 for a quantity of 709,262 barrels. On May 6, 2021, 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 Fixed Price		Type of Contract	Index	Barrels	Weighted Average Price
April 2021 to January 2022	Swaps	Dated Brent	550,523	$	53.10
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
			550,523					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.

Under the terms of the Etame ~~Marin block~~ 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.~~2028, under the 2018 abandonment study. The amounts paid will be reimbursed through the Cost Account and are non-refundable. ~~The~~In November 2021, an abandonment study was done and the estimate used for this purpose is approximately~~$61.8~~ $81.3 million ($~~36.3~~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, ~~2021~~, ~~$38.9~~2022, $36.3 million ($~~22.9~~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 ~~sheet.~~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 toof the Etame ~~Marin block~~ PSC ~~provides~~ that required these funds to be in U.S. dollars, once the ~~event that~~account for the ~~Gabonese bank fails for any reason to reimburse all~~U.S. dollars abandonment fund is open at BEAC we will resume our funding of the ~~principal and interest due,~~abandonment fund in compliance with the ~~Company and the other joint venture owners shall no longer be held liable for the resulting shortfall in funding the obligation to remediate the sites.~~Etame PSC.

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~~.term. At the Company’s election, the charter could be extended for 2 one-year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. The

performance under the charter guarantee is remote, the Company recorded a liability of ~~$0.2~~$0.1 million as of March 31, ~~2021~~2022 and ~~$0.4~~$0.1 million as of December 31, ~~2020~~2021 representing the guarantee’s estimated fair value. ~~The guarantee of the offshore Gabon FPSO charter has $48.6 million in remaining gross~~Estimated future minimum obligations as of March 31, ~~2021.~~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. TheThe 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. TheThe Company is working with the newly appointed representatives to resolve the audit findings. TheThe 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 July 2019, the Company reached an agreement in principle to resolve a legacy issue related to findings from the Etame Marin block joint venture owners’ audits for the periods from 2007 through 2016 for $4.4 million net to VAALCO. Accordingly, the Company accrued $4.4 million that is reflected in the “Accrued liabilities and other” line item of the Company’s condensed consolidated balance sheet and was recorded as a second quarter 2019 expense in the condensed consolidated statements of operations in the line item “Other operating expense, net”. The final settlement agreements were executed by all the joint venture owners effective September 9, 2019. In October 2019, the Company paid $1.1 million of the $4.4 million. The remaining balance of the amount due was paid in February 2020.

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.~~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 ~~August 2020,~~June 2021, the Company entered into a short-term agreement with an ~~agreement~~affiliate of Borr Drilling Limited to ~~acquire approximately 1,000 square kilometers~~drill a minimum of ~~3-D seismic data in the Company’s Etame Marin block. The acquisition was completed in the fourth quarter of 2020 and the processing~~3 wells with options to drill additional wells. Upon completion of the ~~seismic data began in January 2021. The cost, net~~ETBSM 1HB-ST2 well, the commitment to ~~VAALCO, is estimated to~~Borr Drilling Limited will be ~~approximately $2.0 million to $4.0 million.~~satisfied.

11. LEASES

Under ~~ASC 842,~~ ~~Leases~~,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 ~~Right-of-Use (“ROU”)~~ROU asset and a lease liability at the present value of the future lease payments.

Practical Expedients ~~–The~~– The Company elected to use ~~these~~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. ~~The adoption~~


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Lease cost:	(in thousands)				(in thousands)
Finance lease cost ⁽¹⁾					$	66	$	—
Operating lease cost	$	4,390	$	4,190		4,196		4,390
Short-term lease cost		794		1,032
Variable lease cost		1,434		1,926
Short-term lease cost ⁽²⁾						1,014		794
Variable lease cost ⁽³⁾						1,338		1,434
Total lease expense		6,618		7,148		6,614		6,618
Lease costs capitalized		—		3,281		772		—
Total lease costs	$	6,618	$	10,429	$	7,386	$	6,618

Other information:
Cash paid for amounts included in the measurement of lease liabilities:	2021		2020		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	$	4,773	$	8,510	$	6,551	$	4,773
Weighted-average remaining lease term		1.5 years		2.5 years		0.73 years		1.5 years
Weighted-average discount rate		6.09%		6.16%		5.83%		6.09%

(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.

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,				Three Months Ended March 31,
	2021		2020		2022		2021
	(in thousands)				(in thousands)
Finance lease cost					$	39	$	—
Production expense	$	2,649	$	2,205		3,838		2,649
General and administrative expense		49		49		16		49
Lease costs billed to the joint venture owners		3,920		7,073		3,002		3,920
Total lease expense		6,618		9,327		6,895		6,618
Lease costs capitalized		—		1,102		491		—
Total lease costs	$	6,618	$	10,429	$	7,386	$	6,618

The following table describes the future maturities of the Company’s ~~operating~~ lease liabilities at March 31, ~~2021:~~2022:

Under the joint operating agreements, other joint venture owners are obligated to fund ~~$8.4~~$5.3 million of the ~~$20.3~~$9.0 million in future lease liabilities.

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

The Company is required under the Etame PSC for the Etame Marin block ~~PSC~~in Gabon to conduct ~~regular~~ abandonment studies to update the ~~estimated costs to abandon~~amounts being funded for the eventual abandonment of the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was ~~completed~~prepared in November ~~2018. In 2020,~~2021. At December 31, 2021, associated with the study, the Company recorded ~~$0.4~~an upward revision of $7.2 million ~~in additions associated with~~to the South East Etame 4H development well and $0.2 million in revisions associated with a U.S. property. In connection with the Sasol Acquisition, as discussed in Note 3, the Company added $14.6 million of asset retirement ~~obligations~~obligation primarily as a result of ~~it increasing its interest in~~increased costs expected with the abandonment of the Etame Marin ~~block.~~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.

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~~board of ~~Directors, which~~directors that is generally ~~vest over~~ a ~~service period of up to five years and expire from~~ ~~five~~three-year ~~to ten years~~period, vesting in three equal parts on the anniversaries from the date of ~~grant.~~grant, and may contain performance hurdles.

In March ~~2021,~~2022, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of ~~401,759~~241,358 shares at an exercise price of ~~$3.14~~$6.41 per share and a life of ten years. For each performance stock option award, ~~options with respect to~~ 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 ~~$3.61~~$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 ~~$4.15~~$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 ~~$4.78~~$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. ~~During the three months ended March 31, 2021, 0 performance stock option awards issued under the 2020 Plan were exercised.~~

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

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

Because the Company has not paid cash dividends and does not anticipate paying cash dividends on the common stock in the foreseeable future, no expected dividend yield was input to the Black-Scholes or Monte Carlo models. During the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants inunder the Monte ~~Carlo model.~~Carlo.


	Three Months Ended March 31,					Three Months Ended March 31,
	2021			2020		2022			2021
Weighted average exercise price - ($/share)	$	3.14		$	—	$	6.41		$	3.14
Expected life in years		6.0			—		6.0			6.0
Average expected volatility		75	%		—		72	%		75	%
Risk-free interest rate		0.95	%		—		1.98	%		0.95	%
Expected dividend yield							2.30	%		—
Weighted average grant date fair value - ($/share)	$	2.07		$	—	$	2.84		$	2.07

Stock option activity associated with the Monte Carlo model for the three months ended March 31, ~~2021~~2022 is provided below:


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value	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)	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2021	644		1.23
Outstanding at January 1, 2022							359	$	1.96
Granted	402		3.14				241		6.41
Exercised	—		—				—		—
Unvested shares forfeited	(137)		1.96				—		—
Vested shares expired	—		—				—		—
Outstanding at March 31, 2021	909		1.96	9.51	$	566
Exercisable at March 31, 2021	—	$	—	—	$	—
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, ~~2021~~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)	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at January 1, 2021	1,804		1.38
							(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2022							615	$	1.58
Granted	—		—				—		—
Exercised	(305)		1.13				(171)		1.16
Unvested shares forfeited	(7)		2.33				—		—
Vested shares expired	—		—				—		—
Outstanding at March 31, 2021	1,492		1.43	1.68	$	1,248
Exercisable at March 31, 2021	1,323	$	1.31	1.52	$	1,248
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, ~~2021, 122,413 shares were added to treasury as a result of tax withholding on options exercised. During the three months ended March 31, 2020, 0~~2022, 28,761 shares were added to treasury as a result of tax withholding on options exercised.

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 ~~2021,~~2022, the Company issued ~~526,147~~353,424 shares of ~~service- based~~service-based restricted stock to employees, with a grant date fair value of ~~$3.14~~$6.41 per share. The vesting of these shares is dependent upon, among other things, the employees’ and directors’ continued service with the Company.

During the three months ended March 31, ~~2021, 32,931 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the three months ended March 31, 2020, 34,459~~2022, 35,232 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.

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~~board of ~~Directors.~~directors. In addition, SARs will become exercisable upon a change in control, unless provided otherwise by the Compensation Committee of the Company’s ~~Board~~board of ~~Directors.~~directors.

During the three months ended March 31, ~~2021 and 2020,~~2022, the Company did 0t grant SARs to employees or directors.

SAR activity for the three months ended March 31, ~~2021~~2022 is provided below:


	Number of Shares Underlying SARs	Weighted Average Exercise Price Per Share		Term	Aggregate Intrinsic Value		Number of Shares Underlying SARs	Weighted Average Exercise Price Per Share		Term	Aggregate Intrinsic Value
	(in thousands)			(in years)		(in thousands)	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2021	2,940		1.33
Outstanding at January 1, 2022							362	$	1.81
Granted	0		—				0		—
Exercised	(552)		1.17				(59)		1.41
Unvested SARs forfeited	(14)		2.33				—		—
Vested SARs expired	—		—				—		—
Outstanding at March 31, 2021	2,374		1.36	2.02	$	2,151
Exercisable at March 31, 2021	2,027	$	1.23	1.86	$	2,082
Outstanding at March 31, 2022							303	$	1.89	1.75	$	1,402
Exercisable at March 31, 2022							237	$	1.94	1.65	$	1,086

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.

~~The~~VAALCO and its domestic subsidiaries file a consolidated U.S. income tax ~~provision for VAALCO consists primarily of Gabonese and United States income taxes. The Company’s operations in other~~return. Certain foreign jurisdictions have a 0% effective tax rate because the Company has incurred losses in those countries and has full valuation allowances against the corresponding net deferred tax assets. The Company files incomesubsidiaries also file tax returns in ~~all jurisdictions where such requirements exist, with Gabon and the United States being its primary tax~~their respective local jurisdictions.

~~For interim reporting periods,~~Income taxes attributable to continuing operations for the ~~Company determines its tax expense by estimating an annual effective~~three months ended March 31, 2022, and 2021 are attributable to foreign taxes payable in Gabon as well as income tax rate based on current and forecasted business results and enacted tax laws on a quarterly basis and applies this tax rate to the Company’s ordinary income or loss to calculate its estimated tax expense or benefit. The tax effect of discrete items is recognizedtaxes in the ~~period in which they occur at the applicable statutory tax rate.~~

In March 2020, the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) became law. The CARES Act, among other things, includes provisions to obtain alternative minimum tax credit refunds for which the Company qualifies. The Company has analyzed the different aspects of the CARES Act and implemented the applicable provisions, which had no material impact on the Company.U.S.

Provision for income ~~tax expense (benefit)~~taxes related to income from continuing operations consists of the following:


	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, ~~2021~~2022 and ~~2020,~~2021, excluding the impact of discrete items, was ~~(64%)~~67.9% and ~~(68%~~(64%), respectively. For the three months ended March 31, ~~2021,~~2022, the Company’s overall effective tax rate was impacted by non-deductible items associated with operations, ~~the impact of deducting foreign taxes rather than crediting them,~~ and a change in valuation allowance. The ~~valuation allowance was necessary due to the decline in crude oil prices caused by declining global economic activity and excess oil supply. The~~ total ~~change in valuation allowances~~tax expense for the three months ended March 31, ~~2021~~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 $3.1 million unfavorable oil price adjustment as a result of the change in value of the government of Gabon’s allocation of Profit Oil between the time it was ~~$(2.3) million.~~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’s~~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, ~~2021,~~2022, the Company had 0 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.

‎

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

~~SPECIAL NOTE~~CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes ~~“forward-looking~~“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 ~~Quarterly~~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:~~to:

the impact of the coronavirus (“COVID-19”) pandemic, including ~~the sharp decline in the~~its impact on global demand for crude oil ~~which resulted in a significant global oversupply of crude oil~~ and ~~steep decline in~~ 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 ~~find a replacement for~~effectively replace the floating, production, storage and offloading vessel (“FPSO”) ~~or to renew the FPSO charter;~~;

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;

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, ~~2020~~2021 (“~~2020~~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 ~~2020~~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 ~~“Special Note~~“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.

A significant component of our results of operations is dependent upon the difference between prices received for our offshore Gabon crude oil production and the costs to find and produce such crude oil. Historically, crude oil and natural gas prices have been volatile and subject to fluctuations based on a number of factors beyond our control. More recently, crude oil and natural gas prices have been in the midst of an unprecedented decline due to a combination of factors, including a substantial decline in global demand for oil caused by the COVID-19 pandemic and subsequent mitigation efforts. Despite these challenges, we remain committed to generating long-term value for our stockholders by focusing on exploration and development of existing properties, adding value with accretive acquisitions, controlling costs and optimizing production.

RECENT DEVELOPMENTS

~~Impact on Operations of COVID-19 Pandemic and the Current Crude Oil Pricing Environment~~Marine Construction Agreement for Subsea Reconfiguration

On March ~~11, 2020,~~17, 2022, VAALCO Gabon, SA (“VAALCO Gabon”), a wholly owned subsidiary of the ~~World Health Organization classified~~Company, entered into an Agreement for the ~~outbreak~~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 ~~strain~~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 ~~coronavirus (“COVID-19”~~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 ~~pandemic, based on the rapid increase in global exposure. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil~~day rate, subject to certain conditions, as set forth in the ~~oil~~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 ~~gas industry,~~Panoro Energy (the “BWE Consortium”) and that the ~~full impact of~~BWE Consortium has been provisionally awarded two blocks in the ~~outbreak continues to evolve. The adverse economic effects of the COVID-19 outbreak have materially decreased demand for crude oil based on the restrictions~~12th Offshore Licensing Round in place by governments trying to curb the outbreak and changes in consumer behavior. This has led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices. In April 2020, countries within OPEC+, which includes Gabon, reached an agreement to cut crude oil production to reduce the gap between excess supply and demand, in an effort to stabilize the international oil market. Gabon has undertaken measures to comply with such OPEC+ production quota agreement and, as a result, the Minister of Hydrocarbons in Gabon requested that we reduce our production. In response to such request from the Minister of Hydrocarbons, we temporarily reduced production from the Etame Marin block beginning in July 2020 and expect such reduction to continue through June 30, 2021. Reductions in production have significantly improved the demand/supply imbalance, and crude oil prices have improved from the lows seen in March and April of 2020. We currently have crude oil commodity swap agreements for aGabon. The award is subject

~~total~~to concluding the terms of ~~709,262 barrels at~~production sharing contracts (“PSCs”) with the Gabonese government. BW Energy will be the operator with a ~~Dated Brent weighted average price of $53.10 per barrel for the period from~~37.5% working interest, with VAALCO (37.5% working interest) and including February 2021 through January 2022 to mitigate the effects of potential future price declines. We will consider entering into additional commodity derivative instruments from time to time. However, there can be no assurance when, or upon what terms, we may enter into any future commodity derivative instruments.

~~While we did not incur significant disruptions to operations during the three months ended March 31, 2021~~Panoro Energy (25% working interest) as ~~a result of the COVID-19 pandemic, we~~non-operating joint owners. The two blocks, G12-13 and H12-13, are unable to predict the impact that the COVID-19 pandemic will have on us in the future, including our financial position, operating results, liquidity and ability to obtain financing in future reporting periods, due to numerous uncertainties. These uncertainties include the severity of the virus, the duration of the outbreak, governmental or other actions taken to combat the virus (which could include limitations on our operations or the operations of our customers and vendors), and the effect that the COVID-19 pandemic and the current crude oil price wars among global suppliers will have on the demand for crude oil. 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 vitaladjacent to our ~~operations. We are unable to predict the extent of the impact that the continuing spread of COVID-19 throughout Gabon may have on our ability to continue to conduct our operations.~~

~~Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets~~Etame PSC as well as ~~other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors~~BW Energy and ~~contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid~~Panoro’s Dussafu PSC offshore Southern Gabon, and ~~unpredictable,~~cover an area of 2,989 square kilometers and ~~we are actively managing our response and assessing potential impacts to our financial position and operating results, as well as any adverse developments that could impact our business.~~1,929 square kilometers, respectively.

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

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

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

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

~~implemented cost cutting measures with vendors;~~

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

~~ceased or deferred certain discretionary capital spending.~~

We expect to continue to take proactive steps to manage any disruption in our business caused by COVID-19 and to protect the health and safety of our employees. However, the health and safety measures we and our vendors have taken have resulted in us incurring higher costs. As a result of these factors and the conditions described above, 2020 was one of the most uncertain and disruptive years that the industry has ever seen. Accordingly, the results presented herein are not necessarily indicative of future operating results.

~~Recent Operational Updates~~

In December 2020, we completed the acquisition of approximately 1,000 square kilometers of new dual-azimuth proprietary 3-D seismic data over the entire Etame Marin block. We expect the seismic data to enhance sub-surface imaging by merging legacy data with newly acquired seismic allowingCharter Agreement for the ~~first continuous 3-D seismic over the entire block. The processing of the seismic data began in January 2021,~~Floating Storage and we expect all the data to be fully processed and analyzed by the fourth quarter of 2021. The seismic data will be used to optimize and de-risk future drilling locations and potentially identify new drilling locations. We plan to commence the next drilling campaign at Etame in late 2021 or early 2022 with two development wells and two appraisal wells at an estimated cost of $115.0 million to $125.0 million gross, or $73.0 million to $79.0 million, net to VAALCO’s 63.6% participating interest. The locations of these wells will be determined in conjunction with the new seismic processing and interpretation.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. ~~Our~~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 ~~include securing a new storage vessel, either under a charter agreement or a purchase, purchasing~~to drill additional wells. On October 4, 2021, we novated the ~~vessel under~~Borr Jack-Up XIV Inc contract with Borr West Africa Assets, Inc. In December of 2021, we spudded the ~~current FPSO charter pursuant~~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 ~~option~~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 ~~charter contract or extending~~Etame license, with the ~~charter agreement for~~potential to complete and produce from the ~~current FPSO. Execution of any of these options requires significant lead time and may require a capital investment due to the specialized nature of such vessels.~~Dentale in this well. We are currently ~~evaluating our alternatives so that we will be in position~~planning to ~~have an alternative in place when~~drill a fourth well following the ~~current charter expires. In April 2021, we signed a non-binding letter~~ETBSM 1HB-ST2 well as part of ~~intent with Omni Offshore Terminals Pte Ltd (“Omni”) to provide and operate a floating storage and offloading (“FSO”) unit at our Etame Marin field for up to 11 years upon~~its 2021/2022 drilling campaign.

We estimate the ~~expiration~~range of cost of the ~~current FPSO contract (the “Omni FSO Proposal”).~~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 ~~sale and purchase agreement (“SPA”)~~SPA to acquire ~~Sasol Gabon S.A.’s (“Sasol’s”)~~Sasol’s 27.8% working interest in the Etame Marin block offshore ~~Gabon (the “Sasol Acquisition”).~~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%~~, almost doubling our total production and reserves.~~. 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

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the three months ended March 31, ~~2021~~2022 and ~~2020~~2021 are as follows:


	Three Months Ended March 31,						Three Months Ended March 31,
	2021		2020		Increase (Decrease) in 2021 over 2020		2022		2021		Increase (Decrease) in 2022 over 2021
	(in thousands)						(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	13,453	$	8,896	$	4,557	$	26,407	$	13,453	$	12,954
Net change in operating assets and liabilities		(11,698)		18,749		(30,447)		(27,147)		(11,698)		(15,449)
Net cash provided by continuing operating activities		1,755		27,645		(25,890)
Net cash (used in) provided by continuing operating activities								(740)		1,755		(2,495)
Net cash used in discontinued operating activities		(13)		(18)		5		(18)		(13)		(5)
Net cash provided by operating activities		1,742		27,627		(25,885)
Net cash (used in) provided by operating activities								(758)		1,742		(2,500)

Net cash used in investing activities		(19,056)		(11,980)		(7,076)		(23,148)		(19,056)		(4,092)

Net cash used in continuing financing activities		(56)		(652)		596
Net cash used in financing activities		(56)		(652)		596		(2,118)		(56)		(2,062)
Net change in cash, cash equivalents and restricted cash	$	(17,370)	$	14,995	$	(32,365)	$	(26,024)	$	(17,370)	$	(8,654)

The ~~$4.6~~$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, ~~2021~~2022 compared to the same period of ~~2020~~2021, was mainly due to ~~higher crude oil prices~~positive contributions from adding back to cash the change in ~~2021 partially offset by higher operating costs and expenses as discussed below in~~ ~~“Results of Operations~~”.unrealized derivative losses. The net decrease in operating assets and liabilities of ~~$30.4~~$15.4 million for the three months ended March 31, ~~2021~~2022 compared to the same period of ~~2020~~2021 was primarily related to ~~increases~~an increase in ~~accounts receivable, accrued liabilities and foreign income taxes payable,~~assets of $25.5 million which was partially offset by ~~decreases~~a $10.1 million increase in ~~crude oil inventory and accounts payable.~~liabilities.

~~Net~~The $4.1 million increase in net cash used in investing activities during the three months ended March 31, ~~2021 included $17.9 million paid~~2022 was due to increases in capital spending in 2022 for the ~~completion of~~Etame-8H development well and Etame field reconfiguration and other items to support the Sasol Acquisition as discussed in Note 3 to our condensed consolidated financial statements. In addition, we incurred on a cash basis $1.2 million for property and equipment primarily related to equipment and enhancements as well as expenditures related the next2021/2022 drilling ~~program as discussed in “Recent Operational Updates” above. During~~Campaign. For the three months ended March 31, ~~2020, we incurred on a~~2021, cash ~~basis $12.0 million for expenditures related~~used in investing activities was mainly due to cash used in the ~~2019/2020 drilling campaign and equipment purchases. See “Capital Expenditures~~”~~below for further discussion.~~purchase of Sasol’s interest in the Etame Block.

Net cash used in financing activities during the three months ended March 31, ~~2021~~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. Net cash used~~statements, partially offset by $0.2 million in ~~financing activities during~~proceeds from options exercised.

For the three months ended March 31, ~~2020 included $0.7~~2022 we had accrual basis capital expenditures attributable to continuing operations of $31.8 million ~~for treasury stock purchases primarily made under~~compared to $2.5 million accrual basis capital expenditures in 2021, excluding the ~~Company’s stock repurchase plan.~~

~~During~~Sasol acquisition. For the three months ended March 31, ~~2021, we incurred accrual basis capital expenditures of $2.5 million. These expenditures~~2022, our efforts were primarily related to equipment and enhancements as wells and the next drilling program. The difference between capital expenditures and the property and equipment expenditures reported in the consolidated statements of cash flows is attributable to changes in accruals for costs incurred but not yet invoiced or paidfocused on ~~the report dates. Capital expenditures in 2020 were attributable to expenditures~~spending related to the ~~2019/2020~~2021/2022 drilling ~~program, seismic acquisition costs, equipment~~campaign and ~~enhancements. As discussed above, we anticipate beginning a drilling program late~~Etame field reconfigurations and FSO projects. During the same time in 2021, ~~that will continue into~~ our spending was concentrated on the Sasol acquisition and obtaining certain long lead items for the 2021/2022 which will require significant capital investment in 2021 and 2022. In April 2021, we purchased a workover unit to have on site for approximately $1.9 million for future maintenance work. As discussed above, we signed a non-binding letter of intent with Omni to provide and operate a FSO unit at our Etame Marin field. The estimated capital investment is $40.0 million to $50.0 million gross ($25.0 million to $32.0 million net to VAALCO) for deployment of the Omni FSO and the required field reconfiguration, with approximately 20% expected to be invested in the second half of 2021 and the balance in 2022 and with an anticipated payback of less than three years.

See ~~Notes 10~~table below in “Capital Resources, Liquidity and ~~11 to the condensed consolidated financial statements as well as Notes 12~~Cash Requirements” for further information.

Regulatory and ~~13 to our 2020 Form 10-K for discussion of our contractual obligations. There were no other material changes in our contractual obligations during the three months ended March 31, 2021.~~Joint Interest Audits

~~Regulatory and Joint Interest Audits~~

We are subject to periodic routine audits by various government agencies in Gabon, including audits of our petroleum ~~cost account,~~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 ~~condensed consolidated financial statements~~Financial Statements for further discussion.

~~Capital Resources~~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, ~~2021,~~2022, we had unrestricted cash of ~~$19.3~~$18.9 million. ~~The unrestricted~~We invest cash ~~balance includes $1.7 million of cash attributable to non-operating joint venture owner advances.~~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~~project-related activities on behalf of our working interest joint venture owners. We generally obtain advances from ~~the~~ 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 ~~February~~January 2020 and ends in July ~~2021.~~2022. Pricing under ~~the~~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.

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,

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%. We expect that part of this increase will be offset by an increase in our operating cash flows based on our increased portion of the Etame production. 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. In early March 2020, crude oil prices declined significantly ending at approximately $15 per barrel for Brent crude, as of March 31, 2020, as a result of market concerns about the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. While OPEC and Russia were able to reach an agreement to cut production in April 2020, crude oil prices continued to decline below $20 per barrel for Brent crude asAs a result of the ~~substantial decline~~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 ~~global~~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.

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 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.

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 ~~caused~~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 COVID-19 pandemic and subsequent mitigation efforts. The reduced demand for crude oil as a result of measures taken to prevent the spread of COVID-19 led to a surplus in the global supply of crude oil. Reductions inprior production ~~have significantly improved the demand/supply imbalance and crude oil prices have improved from the lows seen in March and April of 2020.~~cuts. Brent crude prices were approximately ~~$63~~$107 per barrel as of March 31, ~~2021.~~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 ~~January 22,~~September 24, 2021, we entered ~~into~~ commodity swaps at a Dated Brent weighted average price of ~~$53.10~~$72.00 per barrel for the period from and including ~~February 2021 through January~~March 2022 to June 2022 for ~~709,262~~a quantity of 460,000 barrels. On ~~May~~January 6, ~~2021,~~2022, we entered into additional commodity swaps at a Dated Brent weighted average price of ~~$66.51~~$76.53 per barrel for the period from and including ~~May 2021 through October 2021~~July 2022 to September 2022 for a quantity of ~~672,533~~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.

~~Despite~~See the lower Brent crude oil prices, based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations to support our cash requirements, including those related totable below for the ~~Sasol Acquisition, through June 2022. We are continuing to evaluate all uses~~unexpired barrels as of ~~cash and whether to pursue growth opportunities or preserve our resources in light of ongoing economic conditions.~~March 31, 2022:

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

~~OFF-BALANCE SHEET ARRANGEMENTS~~


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

~~None.~~

CRITICAL ACCOUNTING POLICIES

There have been no material changes to our critical accounting policies subsequent to December 31, ~~2020.~~2021.

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

RESULTS OF OPERATIONS

Three Months Ended March 31, ~~2021~~2022 Compared to the Three Months Ended March 31, ~~2020~~2021

Net income for the three months ended March 31, ~~2021 of $9.9~~2022 was $12.2 million compared to net ~~loss~~income of ~~$52.8~~$9.9 million for the same period of ~~2020.~~2021. See discussion below for changes in revenue and expense.

Crude oil and natural gas revenues increased ~~$21.4~~$28.9 million, or approximately ~~116.3%~~72.6%, during the three months ended March 31, ~~2021~~2022 compared to the same period of ~~2020.~~2021. The increase in revenue is attributable to higher ~~volumes and to a lesser degree higher~~ sales prices ~~as described. Further discussion of results by significant line item follows.~~and Sasol’s additional working interest for the full three months ended March 31, 2022.


	Three Months Ended March 31,						Three Months Ended March 31,
	2021		2020		Increase/(Decrease)		2022		2021		Increase/(Decrease)
	(in thousands except per bbl information)						(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		619		294		325		616		619		(3)
Average crude oil sales price (per Bbl)	$	61.31	$	59.54	$	1.77	$	109.65	$	61.31	$	48.34

Net crude oil revenue	$	39,774	$	18,389	$	21,385	$	68,656	$	39,774	$	28,882

Operating costs and expenses:
Production expense		16,133		9,749		6,384		18,360		16,133		2,227
Exploration expense		142		—		142		127		142		(15)
Depreciation, depletion and amortization		4,148		3,103		1,045		4,673		4,148		525
Impairment of proved crude oil and natural gas properties		—		30,625		(30,625)
General and administrative expense		4,547		754		3,793		4,994		4,547		447
Bad debt expense		101		810		(709)		492		101		391
Total operating costs and expenses		25,071		45,041		(19,970)		28,646		25,071		3,575
Other operating expense, net		(360)		(31)		(329)		(5)		(360)		355
Operating income (loss)	$	14,343	$	(26,683)	$	41,026
Operating income							$	40,005	$	14,343	$	25,662

The revenue changes in the three months ended March 31, ~~2021~~2022 compared to the same period in ~~2020~~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~~.periods.

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 ~~three~~ two liftings during the three months ended March 31, ~~2021~~2022 and ~~two~~three liftings during the three months March 31, ~~2020.~~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 ~~53,858~~174,250 barrels and ~~188,971~~53,858 barrels at March 31, ~~2021~~2022 and ~~2020,~~2021, respectively.

Production expenses increased ~~$6.4~~$2.2 million, or approximately ~~65.5%~~13.8%, infor the three months ended March 31, ~~2021~~2022 compared to the same period in ~~2020.~~2021. The increase in expense was primarily related to higher ~~crude oil inventory~~FPSO costs, boat expense, personnel, costs, and ~~FPSO charter costs partially offset by lower workover and transportation~~domestic market obligation (“DMO”) costs. On a per barrel basis, production expense, excluding workover expense, for the three months ended March 31, ~~2021~~2022 increased to ~~$26.02~~$29.81 per barrel from ~~$23.39~~$26.02 per barrel for the three months ended March 31, ~~2020~~2021 primarily as a result of ~~an increase~~lower

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.~~pandemic for each of the three months ended March 31, 2022 and 2021, respectively.

Depreciation, depletion and amortization costs increased ~~$1.0~~$0.5 million, or approximately ~~33.7%~~12.7% due to the higher depletable ~~costs associated with~~base as a result of capital expenditures related to the ~~Sasol Acquisition.~~2021/2022 drilling program.

General and administrative expenses increased ~~$3.8~~$0.4 million, or approximately ~~503.1%~~9.8% in the three months ended March 31, ~~2021~~2022 compared to the same period of ~~2020.~~2021. The increase in expense was primarily related to ~~a $4.0~~increase on wages and salaries $0.4 million, increase in SARs expense. SARs liability awards are measured at fair value. The primary driver of changes in the fair value of these awards is changes in the Company’s stock price. See Note 14 to our condensed consolidated financial statements for further discussion.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 ~~lower~~higher between the three months ended March 31, ~~2021~~2022 and ~~2020~~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 ~~with the VAT allowance.~~TVA balance has also increased as we have received no payments related to these balances in 2022.

Other operating ~~expense,~~income (expense), net for the three months ended March 31, ~~2021 increased primarily due to $0.4 million~~2022 and for the ~~change in fair value of the contingent consideration payment.~~three months ended March 31, 2021 was not material to our results.

Derivative instruments ~~gain (loss),~~loss, net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The ~~$6.0~~$31.8 million ~~loss~~and $6.0 million losses for the three months ended March 31, 2022 and 2021 isare a result of the increase in the price of Dated Brent crude oil during the ~~three months ended March 31,~~two periods. Every quarter in 2021 ~~as compared to a decrease~~and continuing in 2022 Dated brent crude oil process have increased. Since the ~~price of~~Company owes the counterparty for any Dated Brent ~~crude oil that resulted~~price over the initial per barrel value and the Company continued to place on additional hedges in ~~a $7.3 million gain during~~2021 and 2022, the ~~comparable prior year period.~~loss associated with the derivates have increased. Our derivative instruments ~~only~~currently cover a portion of our production through ~~January~~September 2022.

Other, net for the three months ended March 31, ~~2021~~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, ~~2021~~2022 was ~~$3.1~~a benefit of $4.6 million. This is comprised of $ ~~(0.3)~~12.5 million of deferred tax benefit and a current tax expense of ~~$3.4~~$ (5.7) million. ~~The deferred income tax benefit for the three months ended March 31, 2021 included a $(2.3) million decrease~~See Note 15 to the ~~valuation allowances on U.S. and Gabonese deferred tax assets offset by a $3.9 million deferred tax expense. Income tax expense for the three months ended March 31, 2020,~~ condensed consolidated financial statements.

~~includes $35.6 million of deferred tax expense and a current tax benefit of $(2.2) million~~. The deferred income tax expense for the three months ended March 31, 2020 included a $46.9 million charge to increase the valuation allowances on U.S. and Gabonese deferred tax assets offset by an $11.8 million deferred tax benefit. For both the three months ended March 31, 2021 and 2020, our overall effective tax rate was impacted by non-deductible items associated with operations and deducting foreign taxes rather than crediting them for United States tax purposes.

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~~Central African CFA ~~Franc”,~~Franc, or ~~“XAF”)~~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, ~~2021,~~2022, we had net monetary assets of ~~$8.2~~$11.1 million (XAF ~~4,590.3~~6,525.3 million) ~~(net to VAALCO)~~ denominated in XAF. A 10% weakening of the CFA ~~Franc~~ relative to the U.S. dollar would have a ~~$ (0.7)~~$1.0 million reduction in the value of these net assets. For the three months ended March 31, ~~2021,~~2022, we had expenditures of approximately ~~$3.9~~$7.3 million ~~(net to VAALCO),~~ 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

crude oil sales were to remain constant at the most recent quarterly sales volumes of ~~619~~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.~~income (loss).

As of March 31, ~~2021,~~2022, we had ~~crude oil swaps outstanding. In the past, we have used~~unexpired derivative instruments asoutstanding covering 954 MBbls of production through September 2022. These instruments were intended to be an economic hedge against declines in crude oil prices; however, ~~such instruments~~they were not designated as hedges for accounting purposes. ~~Our derivative instruments only cover a portion of our production through January 2022.~~ 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, ~~2021,~~2022, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were ~~effective.~~effective at the reasonable assurance level.

~~CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING~~

~~The internal control environment was impacted by the stay-at-home requirements for our Houston and Gabon staff which began~~Changes in ~~mid-March 2020 and continues through the date of this report. While modifications were made to the manner in which controls were performed, these changes did not have a material effect on our~~ internal control over financial reporting ~~and there~~

~~were~~There have been no changes in our internal control over financial reporting ~~that occurred~~ during the three months ended March 31, ~~2021~~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 ~~all~~none of the claims and litigation we are currently involved in are ~~not~~ 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 ~~2020~~2021 Form 10-K. ~~Except as set forth below, there~~There have been no material changes in our risk factors from those described in our ~~2020~~2021 Form 10-K.

We may never enter into a definitive binding agreement with Omni to provide and operate an FSO unit for the storage of the crude oil that we produce, and if we are not able to timely secure a method of storing the crude oil before the expiration of the FPSO contract in September 2022, our results of operations could be materially adversely affected.

As an offshore producer, we depend on our floating, production, storage and offloading vessel (“FPSO”) to store all of the crude oil we produce prior to sale to our customers. Our current FPSO contract expires in September 2022. We are currently evaluating our alternatives so that we will be in position to have an alternative in place when the current charter expires. Our options include securing a new storage vessel, either under a charter agreement or a purchase, purchasing the vessel under the current FPSO charter pursuant to an option in the charter contract or extending the charter agreement for the current FPSO.

In April 2021, we signed a non-binding letter of intent with Omni Offshore Terminals Pte Ltd (“Omni”) to provide and operate a floating storage and offloading (“FSO”) unit at our Etame Marin field for up to 11 years upon the expiration of the current FPSO contract (the “Omni FSO Proposal”).

Our obligations under the letter of intent are subject to a number of conditions, including completion of due diligence to each party’s satisfaction and the negotiation and execution of a definitive agreement, and there is no assurance these conditions will be satisfied. Any definitive agreement may differ materially from the letter of intent and may contain conditions to closing, which may or may not be satisfied or waived by the parties. In addition, any such agreement will be subject to board approval by both parties as well as Etame joint-owner and Gabonese government approvals. Further, although we have no present intention to terminate the LOI or to abandon the Omni FSO Proposal, we may seek other opportunities if it is in the best interests of the Company.

~~For all of the foregoing reasons, there is no assurance that we will be able to agree to terms on a definitive binding agreement with Omni upon the expiration of the current FPSO contract, or at all.~~

Execution of any of the storage options, including the Omni FSO Proposal, requires significant lead time and may require a capital investment due to the specialized nature of such vessels. To become operational, significant engineering studies, platform modifications, mooring and pipeline surveys as well as installation must be completed. If we are not able to timely secure an alternative method of storing the crude oil we produce, then we will not be able to sell crude oil to our customers. Consequently, we



PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets
March 31, ~~2021~~2022 and December 31, ~~2020~~2021	2
Condensed Consolidated Statements of Operations
Three Months Ended March 31, ~~2021~~2022 and ~~2020~~2021	3
Condensed Consolidated Statements of Shareholders’ Equity
Three Months Ended March 31, ~~2021~~2022 and ~~2020~~2021	4
Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, ~~2021~~2022 and ~~2020~~2021	5
Notes to Condensed Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2729
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	3437
ITEM 4. CONTROLS AND PROCEDURES	3538
PART II. OTHER INFORMATION	3538
ITEM 1. LEGAL PROCEEDINGS	3538
ITEM 1A. RISK FACTORS	35
~~ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES~~	3638
ITEM 6. EXHIBITS	3639


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
	(in thousands)				(in thousands)
Allowance for bad debt
Balance at beginning of period	$	(2,273)	$	(1,508)	$	(5,741)	$	(2,273)
Bad debt charge		(101)		(810)
Adjustment associated with reversal of allowance on Mutamba receivable		—		593
Bad debt charge, net of receipts						(492)		(101)
Adjustment associated with Sasol Acquisition		(2,879)		—		—		(2,879)
Foreign currency gain (loss)		161		—
Foreign currency gain						98		161
Balance at end of period	$	(5,092)	$	(1,725)	$	(6,135)	$	(5,092)


	Three Months Ended March 31,				Three Months Ended March 31,
	2021		2020		2022		2021
Revenue from customer contracts:	(in thousands)
Sales under the COSPA	$	43,829	$	20,444	$	76,486	$	43,829
Other items reported in revenue not associated with customer contracts:
Carried interest recoupment		1,822		885		1,112		1,822
Royalties		(5,877)		(2,940)		(8,942)		(5,877)
Total revenue, net	$	39,774	$	18,389
Crude oil and natural gas sales					$	68,656	$	39,774


	Lease Obligation		Operating Leases		Finance Leases
Year	(in thousands)		(in thousands)
2021	$	10,437
2022		9,685	$	6,397	$	311
2023		179		371		368
2024				197		368
2025				33		368
Thereafter				—		537
		20,301		6,998		1,952
Less: imputed interest		852		108		201
Total lease liabilities	$	19,449	$	6,890	$	1,751


	Restricted Stock	Weighted Average Grant Date Fair Value		Restricted Stock	Weighted Average Grant Date Fair Value
	(in thousands)			(in thousands)
Non-vested shares outstanding at January 1, 2021	1,155	$	1.30
Non-vested shares outstanding at January 1, 2022				741	$	2.36
Awards granted	526		3.14	353		6.41
Awards vested	(125)		1.37	(129)		3.07
Awards forfeited	(89)		1.98	(26)		3.06
Non-vested shares outstanding at March 31, 2021	1,467	$	1.91
Non-vested shares outstanding at March 31, 2022				939	$	3.77


	As of March 31,				As of March 31,
	2021		2020		2022		2021
	(in thousands)				(in thousands)
Cash and cash equivalents	$	19,251	$	60,973	$	18,939	$	19,251
Restricted cash - current		82		994		4,230		82
Restricted cash - non-current		1,752		925		1,752		1,752
Abandonment funding		22,862		11,227		21,369		22,862
Total cash, cash equivalents and restricted cash	$	43,947	$	74,119	$	46,290	$	43,947


		Three Months Ended March 31,					Three Months Ended March 31,
Derivative Item	Statement of Operations Line	2021		2020		Statement of Operations Line	2022		2021
		(in thousands)					(in thousands)
Crude oil swaps	Realized gain (loss) - contract settlements	$	(1,710)	$	718	Cash settlements paid on matured derivative contracts, net	$	(12,500)	$	(1,710)
	Unrealized gain (loss)		(4,244)		6,621	Cash settlements not paid on matured derivative contracts, net		(19,258)		(4,244)
	Derivative instruments gain (loss), net	$	(5,954)	$	7,339	Derivative instruments loss, net	$	(31,758)	$	(5,954)


(in thousands)
Price(1)	$	1,096	$	29,667
Volume		19,351		(184)
Other		938		(601)
	$	21,385	$	28,882


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*	~~Separation~~Amendment No. 1 to Employment Agreement, effective as of January 27, 2022, by and between VAALCO Energy, Inc. and ~~Cary Bounds, dated April 9, 2021~~George Maxwell (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on ~~April 12, 2021~~January 28, 2022 and incorporated herein by reference).
~~10.~~10.22*	Amendment No. 1 to Employment Agreement, effective as of January 27, 2022, by and between VAALCO Energy, Inc. and ~~George Maxwell, effective as of April 19, 2021~~Ronald Bain (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on ~~April 12, 2021~~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).


By	:	/s/ ~~Jason Doornik~~Ronald Bain
		~~Jason Doornik~~Ronald Bain
		Chief ~~Accounting~~Financial Officer ~~and Controller~~ (~~Interim~~ Principal Financial Officer)