egy-20210930x10q

(in thousands)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________

FORM 10-Q

________________________________

(Mark One)

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

For the quarterly period ended September 30, 2021

¨ 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 October 26, 2021, there were outstanding 58,611,072 shares of common stock, $0.10 par value per share, of the registrant.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

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PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
Condensed Consolidated Balance Sheets
September 30, 2021 and December 31, 2020	2
Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2021 and 2020	3
Condensed Consolidated Statements of Shareholders’ Equity
Three and Nine Months Ended September 30, 2021 and 2020	4
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2021 and 2020	5
Notes to Condensed Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	39
ITEM 4. CONTROLS AND PROCEDURES	40
PART II. OTHER INFORMATION	40
ITEM 1. LEGAL PROCEEDINGS	40
ITEM 1A. RISK FACTORS	40
ITEM 6. EXHIBITS	42

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

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PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

VAALCO ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)



	As of September 30, 2021		As of December 31, 2020
ASSETS	(in thousands)
Current assets:
Cash and cash equivalents	$	52,839	$	47,853
Restricted cash		81		86
Receivables:
Accounts with joint venture owners, net of allowance of $0.0 million in both periods presented		1,050		3,587
Foreign income taxes receivable		2,056		—
Other		86		4,331
Crude oil inventory		2,556		3,906
Prepayments and other		5,416		4,215
Total current assets		64,084		63,978

Crude oil and natural gas properties, equipment and other - successful efforts method, net		74,102		37,036
Other noncurrent assets:
Restricted cash		1,752		925
Value added tax and other receivables, net of allowance of $5.8 million and $2.3 million, respectively		5,670		4,271
Right of use operating lease assets		12,984		22,569
Deferred tax assets		24,211		—
Abandonment funding		22,281		12,453
Other long-term assets		1,176		—
Total assets	$	206,260	$	141,232
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	8,433	$	16,690
Accounts with joint venture owners		2,325		4,945
Accrued liabilities and other		39,857		17,184
Operating lease liabilities - current portion		12,671		12,890
Foreign income taxes payable		—		860
Current liabilities - discontinued operations		7		7
Total current liabilities		63,293		52,576
Asset retirement obligations		33,077		17,334
Operating lease liabilities - net of current portion		312		9,671
Other long-term liabilities		—		193
Total liabilities		96,682		79,774
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $25 par value; 500,000 shares authorized, none issued		—		—
Common stock, $0.10 par value; 100,000,000 shares authorized, 69,528,100 and 67,897,530 shares issued, 58,588,777 and 57,531,154 shares outstanding, respectively		6,953		6,790
Additional paid-in capital		76,346		74,437
Less treasury stock, 10,939,323 and 10,366,376 shares, respectively, at cost		(43,847)		(42,421)
Retained earnings		70,126		22,652
Total shareholders' equity		109,578		61,458
Total liabilities and shareholders' equity	$	206,260	$	141,232

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands, except per share amounts)
Revenues:
Crude oil and natural gas sales	$	55,899	$	18,256	$	142,696	$	54,619
Operating costs and expenses:
Production expense		25,208		8,984		57,760		30,859
Exploration expense		479		16		1,286		16
Depreciation, depletion and amortization		6,970		2,212		16,928		8,116
Impairment of proved crude oil and natural gas properties		—		—		—		30,625
General and administrative expense		2,940		2,178		12,221		5,951
Bad debt expense and other		318		151		814		1,140
Total operating costs and expenses		35,915		13,541		89,009		76,707
Other operating income (expense), net		46		(37)		(440)		(883)
Operating income (loss)		20,030		4,678		53,247		(22,971)
Other income (expense):
Derivative instruments gain (loss), net		(5,147)		—		(21,070)		6,583
Interest income, net		3		23		9		150
Other, net		(328)		147		4,088		163
Total other income (expense), net		(5,472)		170		(16,973)		6,896
Income (loss) from continuing operations before income taxes		14,558		4,848		36,274		(16,075)
Income tax expense (benefit)		(17,183)		(2,759)		(11,272)		28,470
Income (loss) from continuing operations		31,741		7,607		47,546		(44,545)
Income (loss) from discontinued operations, net of tax		(20)		11		(72)		(41)
Net income (loss)	$	31,721	$	7,618	$	47,474	$	(44,586)

Basic net income (loss) per share:
Income (loss) from continuing operations	$	0.53	$	0.13	$	0.81	$	(0.77)
Loss from discontinued operations, net of tax		0.00		0.00		0.00		0.00
Net income (loss) per share	$	0.53	$	0.13	$	0.81	$	(0.77)
Basic weighted average shares outstanding		58,586		57,456		58,102		57,628
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	0.53	$	0.13	$	0.80	$	(0.77)
Loss from discontinued operations, net of tax		0.00		0.00		0.00		0.00
Net income (loss) per share	$	0.53	$	0.13	$	0.80	$	(0.77)
Diluted weighted average shares outstanding		58,916		57,741		58,654		57,628

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

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (Unaudited)


	Common Shares Issued	Treasury Shares	Common Stock		Additional Paid-In Capital		Treasury Stock		Retained Earnings		Total
	(in thousands)
Balance at January 1, 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
Shares issued - stock-based compensation	1,092	(314)		109		597		—		—		706
Stock-based compensation expense	—	—		—		117		—		—		117
Treasury stock	—	—		—		—		(765)		—		(765)
Net income	—	—		—		—		—		5,884		5,884
Balance at June 30, 2021	69,420	(10,835)		6,942		75,778		(43,589)		38,405		77,536
Shares issued - stock-based compensation	108	(104)		11		241		—		—		252
Stock-based compensation expense	—	—		—		327		—		—		327
Treasury stock	—	—		—		—		(258)		—		(258)
Net income	—	—		—		—		—		31,721		31,721
Balance at September 30, 2021	69,528	(10,939)	$	6,953	$	76,346	$	(43,847)	$	70,126	$	109,578


	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
Shares issued - stock-based compensation	20	—		2		(2)		—		—		—
Stock-based compensation expense	—	—		—		60		—		—		60
Treasury stock	—	(197)		—		—		(338)		—		(338)
Net income	—	—		—		—		—		596		596
Balance at June 30, 2020	67,819	(10,363)		6,782		73,739		(42,419)		18,629		56,731
Shares issued - stock-based compensation	—	—		—		—		—		—		—
Stock-based compensation expense	—	—		—		322		—		—		322
Treasury stock	—	—		—		—		—		—		—
Net income	—	—		—		—		—		7,618		7,618
Balance at September 30, 2020	67,819	(10,363)	$	6,782	$	74,061	$	(42,419)	$	26,247	$	64,671

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)


	Nine Months Ended September 30,
	2021		2020
	(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	47,474	$	(44,586)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations, net of tax		72		41
Depreciation, depletion and amortization		16,928		8,116
Bargain purchase gain		(7,651)		—
Impairment of proved crude oil and natural gas properties		—		30,625
Other amortization		—		181
Deferred taxes		(24,211)		26,972
Unrealized foreign exchange gain		(342)		(60)
Stock-based compensation		2,098		(2,097)
Cash settlements paid on exercised stock appreciation rights		(3,051)		—
Derivative instruments (gain) loss, net		21,070		(6,583)
Cash settlements received (paid) on matured derivative contracts, net		(10,189)		7,216
Bad debt expense and other		814		1,140
Other operating loss, net		440		83
Operational expenses associated with equipment and other		835		1,418
Cash advance for other long-term assets		(1,176)		—
Change in operating assets and liabilities:
Trade receivables		11,156		8,255
Accounts with joint venture owners		(19)		8,642
Other receivables		94		1,333
Crude oil inventory		4,059		291
Prepayments and other		1,081		(1,153)
Value added tax and other receivables		(1,339)		(919)
Accounts payable		(9,686)		(9,318)
Foreign income taxes receivable/payable		(2,916)		(6,875)
Accrued liabilities and other		1,252		(3,285)
Net cash provided by continuing operating activities		46,793		19,437
Net cash used in discontinued operating activities		(72)		(376)
Net cash provided by operating activities		46,721		19,061
CASH FLOWS FROM INVESTING ACTIVITIES:
Property and equipment expenditures		(8,459)		(22,317)
Acquisition of crude oil and natural gas properties		(22,505)		—
Net cash used in continuing investing activities		(30,964)		(22,317)
Net cash used in discontinued investing activities		—		—
Net cash used in investing activities		(30,964)		(22,317)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuances of common stock		1,305		—
Treasury shares		(1,426)		(990)
Net cash used in continuing financing activities		(121)		(990)
Net cash used in discontinued financing activities		—		—
Net cash used in financing activities		(121)		(990)
NET CHANGE IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		15,636		(4,246)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT BEGINNING OF PERIOD		61,317		59,124
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AT END OF PERIOD	$	76,953	$	54,878

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS SUPPLEMENTAL DISCLOSURES (Unaudited)


	Nine Months Ended September 30,
	2021		2020
	(in thousands)
Supplemental disclosure of cash flow information:
Income taxes paid in-kind with crude oil	$	20,103	$	8,738
Supplemental disclosure of non-cash investing and financing activities:
Property and equipment additions incurred but not paid at end of period	$	4,607	$	1,360
Recognition of right-of-use operating lease assets and liabilities	$	—	$	1,478
Asset retirement obligations	$	14,564	$	359

See notes to condensed consolidated financial statements.

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VAALCO ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND ACCOUNTING POLICIES

VAALCO Energy, Inc. (together with its consolidated subsidiaries “we”, “us”, “our”, “VAALCO,” or the “Company”) is a Houston, Texas based independent energy company engaged in the acquisition, exploration, development and production of crude oil. As operator, the Company has production operations and conducts exploration 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 has discontinued operations associated with activities in Angola, West Africa.

VAALCO’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 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, which includes a summary of the significant accounting policies.

With respect to the novel strain of coronavirus (“COVID-19”), the World Health Organization declared a global pandemic on March 11, 2020. The adverse economic effects of the COVID-19 outbreak 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 led to a significant global oversupply of crude oil and consequently a substantial decrease in crude oil prices in 2020.

In response to the oversupply of crude oil, global 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, between July 2020 and April 2021, the Company temporarily reduced production from the Etame Marin block. Currently, the Company’s production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 and to gradually phase out prior production cuts by September 2022.

The Company considered the impact of the COVID-19 pandemic and the substantial decline in crude oil prices on the assumptions and estimates used 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 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. For the three and nine months ended September 30, 2021, crude oil prices have improved, there have been no disruptions to operations since the beginning of the pandemic, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters removing much of the uncertainty and instability in the industry. Therefore, no additional charges or impairments were required in the three or nine months ended September 30, 2021. The continued spread of COVID-19, including vaccine-resistant strains, or repeated deterioration in crude oil and natural gas prices could result in additional adverse impacts on the Company’s results of operations, cash flows and financial position, including further asset impairments.

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 September 30, 2021 and 2020 each include an escrow amount representing bank guarantees for customs clearance in Gabon. Long-term amounts at September 30, 2021 and 2020 include a charter payment escrow for the floating, production, storage and offloading vessel (“FPSO”) offshore Gabon as discussed in Note 10 and amounts set aside for the future abandonment of the Etame Marin block. The Company invests restricted and excess cash in readily redeemable money market funds.

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


	As of September 30,
	2021		2020
	(in thousands)
Cash and cash equivalents	$	52,839	$	41,986
Restricted cash - current		81		82
Restricted cash - non-current		1,752		925
Abandonment funding		22,281		11,885
Total cash, cash equivalents and restricted cash	$	76,953	$	54,878

The Company conducts abandonment studies from time to time to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. This cash funding is reflected under “Other noncurrent assets” as “Abandonment funding” in the condensed consolidated balance sheets. Future changes to the anticipated abandonment cost estimate could change the asset retirement obligation and the amount of future abandonment funding payments. See Note 12 for further discussion.

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

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

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021			2020	2021		2020
	(in thousands)
Allowance for bad debt
Balance at beginning of period	$	(5,575)	$	(1,904)	$	(2,273)	$	(1,508)
Bad debt charge		(318)		(151)		(814)		(1,140)
Adjustment associated with reversal of allowance on Mutamba receivable		—		—		—		593
Adjustment associated with Sasol Acquisition		—		—		(2,879)		—
Foreign currency gain (loss)		117		—		190		—
Balance at end of period	$	(5,776)	$	(2,055)	$	(5,776)	$	(2,055)

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

The Company records balances resulting from commodity risk management activities in the condensed consolidated balance sheets as either assets or liabilities measured at fair value. Gains and losses from the change in the fair value of derivative instruments and cash settlements on commodity derivatives are presented in the “Derivative instruments gain (loss), net” line item located within the “Other income (expense)” section of the condensed consolidated statements of operations. See Note 8 for further discussion.

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

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

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

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

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

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

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

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

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

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


		As of September 30, 2021
	Balance Sheet Line	Level 1		Level 2		Level 3		Total
		(in thousands)
Liabilities
SARs liability	Accrued liabilities	$	—	$	761	$	—	$	761
Derivative liability - crude oil swaps	Accrued liabilities		—		10,881		—		10,881
		$	—	$	11,642	$	—	$	11,642

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

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

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

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

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

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

A liability for ARO is recognized in the period in which the legal obligations are incurred if a reasonable estimate of fair value can be made. The ARO liability reflects the estimated present value of the amount of dismantlement, removal, site reclamation, and similar activities associated with the crude oil and natural gas properties. The Company uses retirement costs to estimate the expected cash outflows for retirement obligations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. Initial recording of the ARO liability is offset by the corresponding capitalization of asset retirement cost recorded to crude oil and natural gas properties. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability is adjusted, with a corresponding adjustment made to the related asset balance or income statement, as appropriate. Depreciation of the capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for crude oil and natural gas production facilities. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Depreciation, depletion and amortization” in the Company’s condensed consolidated statements of operations. See Note 12 for disclosures regarding the asset retirement obligations. Where there is a downward revision to the ARO that exceeds the net book value of the related asset, the corresponding adjustment is limited to the amount of the net book value of the asset and the remaining amount is recognized as a gain. See Note 12 for further discussion.

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

Income taxes – The Company’s tax provision is based on expected taxable income, statutory rates and tax planning opportunities available to the Company in the various jurisdictions in which the Company operates. The determination and evaluation of the Company’s tax provision and tax positions involves the interpretation of the tax laws in the various jurisdictions in which the Company operates and requires significant judgment and the use of estimates and assumptions regarding significant future events such as the amount, timing and character of income, deductions and tax credits. Changes in tax laws, regulations, agreements and tax treaties or the Company’s level of operations or profitability in each jurisdiction impact the Company’s tax liability in any given year.

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The Company also operates in foreign jurisdictions where the tax laws relating to the crude oil and natural gas industry are open to interpretation, which could potentially result in tax authorities asserting additional tax liabilities. While the Company’s income tax provision (benefit) is based on the best information available at the time, a number of years may elapse before the ultimate tax liabilities in the various jurisdictions are determined. The Company also records as income tax expense the increase or decrease in the value of the government of Gabon’s allocation of Profit Oil, which results due to change in value from the time the obligation is originally produced to the time the obligation is actually paid or satisfied through lifting.

Judgment is required in determining whether deferred tax assets will be realized in full or in part. Management assesses the available positive and negative evidence to estimate if existing deferred tax assets will be utilized, and when it is estimated to be more-likely-than-not that all or some portion of specific deferred tax assets, such as net operating loss carry forwards or foreign tax credit carryovers, will not be realized, a valuation allowance must be established for the amount of the deferred tax assets that are estimated to not be realizable. Factors considered are earnings generated in previous periods, forecasted earnings and the expiration period of net operating loss carry forwards or foreign tax credit carryovers.

In certain jurisdictions, the Company may deem the likelihood of realizing deferred tax assets as remote where the Company expects that, due to the structure of operations and applicable law, the operations in such jurisdictions will not give rise to future tax consequences. For such jurisdictions, the Company has not recognized deferred tax assets. Should the Company’s expectations change regarding the expected future tax consequences, it may be required to record additional deferred taxes that could have a material effect on the Company’s financial position and results of operations. See Note 15 for further discussion.

Earnings per Share – Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities consist of unvested restricted stock awards and stock options using the treasury method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the stock options were exercised are assumed to be used to repurchase shares at the average market price. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 5 for further discussion.

2. NEW ACCOUNTING STANDARDS

Not Yet Adopted

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

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%. As a result of the Sasol Acquisition, the net portion of production and costs relating to the Company’s Etame operations

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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		(10,121)
Bargain purchase gain		(7,651)
Total purchase price	$	38,606

All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items, were recorded at their fair value. The Company used estimated future crude oil prices as of the closing date, February 25, 2021, to apply to the estimated reserve quantities acquired and market participant assumptions to the estimated future operating and development costs to arrive at the estimates of future net revenues. The future net revenues were discounted using the Company’s weighted average cost of capital to determine the fair value at closing. The valuations to derive the purchase price included the use of both proved and unproved categories of reserves, expectation for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates, and risk adjusted discount rates. Other significant estimates were used by the Company to determine the fair value of assets acquired and liabilities assumed. The Company has one year from the date of closing to record purchase price adjustments as a result of changes in such estimates. As a result of comparing the purchase price to the fair value of the assets acquired and liabilities assumed a $7.7 million bargain purchase gain was recognized. A bargain purchase gain of $5.5 million is included in “Other, net” under “Other income (expense)” in the condensed consolidated statements of operations. An income tax benefit of $2.2 million, related to the bargain purchase gain, is also included in the condensed consolidated statements of operations. The bargain purchase gain is primarily attributable to the increase in crude oil price forecasts from the date the SPA was signed, November 17, 2020, to the closing date, February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

The impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $26.4 million and $58.0 million for the three and nine months ended September 30, 2021, respectively, and $10.2 million and $20.1 million increase to “Net income” in the condensed consolidated statements of operations for the three and nine months ended September 30, 2021, respectively.

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

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021			2020
	(in thousands)
Pro forma (unaudited)
Crude oil and natural gas sales	$	55,899	$	34,568	$	160,469		$	103,422
Operating income (loss)		20,030		7,750		63,929			(12,481)
Net income (loss)		31,721		9,136		49,341	(a)		(36,316)	(b)

Basic net income (loss) per share:
Income (loss) from continuing operations	$	0.53	$	0.16	$	0.85		$	(0.63)
Loss from discontinued operations, net of tax		0.00		0.00		0.00			0.00
Net income (loss) per share	$	0.53	$	0.16	$	0.85		$	(0.63)
Basic weighted average shares outstanding		58,586		57,456		58,102			57,628
Diluted net income (loss) per share:
Income (loss) from continuing operations	$	0.53	$	0.16	$	0.84		$	(0.63)
Loss from discontinued operations, net of tax		0.00		0.00		0.00			0.00
Net income (loss) per share	$	0.53	$	0.16	$	0.84		$	(0.63)
Diluted weighted average shares outstanding		58,916		57,741		58,654			57,628

________________

(a)The pro forma net income for the nine months ended September 30, 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 nine months ended September 30, 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 was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1, 2020 to June 30, 2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the contingent payment were met and on April 29, 2021, the Company paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.

Discontinued Operations - Angola

In November 2006, the Company signed a production sharing contract for Block 5 offshore Angola (“Block 5 PSA”). The Company’s working interest was 40%, and the Company carried Sonangol P&P, for 10% of the work program. On September 30, 2016, the Company notified Sonangol P&P that it was withdrawing from the joint operating agreement effective October 31, 2016. On November 30, 2016, the Company notified the national concessionaire, Sonangol E.P., that it was withdrawing from the Block 5 PSA and reduced its activities in Angola. As a result of this strategic shift, the Company classified all the related assets and liabilities as those of discontinued operations in the condensed consolidated balance sheets. The operating results of the Angola segment have been classified as discontinued operations for all periods presented in the Company’s condensed consolidated statements of operations. The Company segregated the cash flows attributable to the Angola segment from the cash flows from continuing operations for all periods presented in the Company’s condensed consolidated statements of cash flows. During three and nine months ended September 30, 2021 and 2020, the Angola segment did not have a material impact on the Company’s financial position, results of operations, cash flows and related disclosures.

4. SEGMENT INFORMATION

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

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Segment activity of continuing operations for the three and nine months ended September 30, 2021 and 2020 as well as long-lived assets and segment assets at September 30, 2021 and December 31, 2020 are as follows:


	Three Months Ended September 30, 2021
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	55,899	$	—	$	—	$	55,899
Depreciation, depletion and amortization		6,953		—		17		6,970
Operating income (loss)		22,834		(271)		(2,533)		20,030
Derivative instruments loss, net		—		—		(5,147)		(5,147)
Income tax expense (benefit)		436		—		(17,619)		(17,183)
Additions to crude oil and natural gas properties and equipment – accrual		6,696		—		—		6,696


	Nine Months Ended September 30, 2021
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	142,696	$	—	$	—	$	142,696
Depreciation, depletion and amortization		16,860		—		68		16,928
Bad debt expense and other		814		—		—		814
Other operating expense, net		(440)		—		—		(440)
Operating income (loss)		64,933		(505)		(11,181)		53,247
Derivative instruments loss, net		—		—		(21,070)		(21,070)
Other, net		7,207		(2)		(3,117)		4,088
Income tax expense (benefit)		8,396		1		(19,669)		(11,272)
Additions to crude oil and natural gas properties and equipment – accrual		10,993		—		—		10,993


	Three Months Ended September 30, 2020
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	18,256	$	—	$	—	$	18,256
Depreciation, depletion and amortization		1,946		—		266		2,212
Bad debt expense and other		151		—		—		151
Operating income (loss)		6,957		(95)		(2,184)		4,678
Income tax expense (benefit)		(2,464)		1		(296)		(2,759)
Additions to crude oil and natural gas properties and equipment – accrual		(306)		—		(9)		(315)



	Nine Months Ended September 30, 2020
(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Revenues-crude oil and natural gas sales	$	54,619	$	—	$	—	$	54,619
Depreciation, depletion and amortization		7,790		—		326		8,116
Impairment of proved crude oil and natural gas properties		30,625		—		—		30,625
Bad debt expense and other		1,140		—		—		1,140
Other operating expense, net		(883)		—		—		(883)
Operating loss		(17,622)		(289)		(5,060)		(22,971)
Derivative instruments gain, net		—		—		6,583		6,583
Income tax expense		19,302		1		9,167		28,470
Additions to crude oil and natural gas properties and equipment – accrual		10,305		—		(9)		10,296



(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Long-lived assets from continuing operations:
As of September 30, 2021	$	63,966	$	10,000	$	136	$	74,102
As of December 31, 2020	$	26,832	$	10,000	$	204	$	37,036

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(in thousands)	Gabon		Equatorial Guinea		Corporate and Other		Total
Total assets from continuing operations:
As of September 30, 2021	$	149,188	$	10,430	$	46,642	$	206,260
As of December 31, 2020	$	101,399	$	10,267	$	29,566	$	141,232

Information about the Company’s most significant customers

The Company currently sells crude oil production from Gabon under term contracts 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 with ExxonMobil Sales and Supply LLC (“Exxon”) that covers sales from February 2020 through January 2022 with pricing based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. During the three and nine months ended September 30, 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 September 30,				Nine Months Ended September 30,
		2021		2020		2021		2020
	(in thousands)
Net income (loss) (numerator):
Income (loss) from continuing operations	$	31,741	$	7,607	$	47,546	$	(44,545)
Income from continuing operations attributable to unvested shares		(404)		(121)		(755)		—
Numerator for basic		31,337		7,486		46,791		(44,545)
(Income) loss from continuing operations attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	31,337	$	7,486	$	46,791	$	(44,545)

Income (loss) from discontinued operations, net of tax	$	(20)	$	11	$	(72)	$	(41)
(Income) loss from discontinued operations attributable to unvested shares		—		—		1		—
Numerator for basic		(20)		11		(71)		(41)
(Income) loss from discontinued operations attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	(20)	$	11	$	(71)	$	(41)

Net income (loss)	$	31,721	$	7,618	$	47,474	$	(44,586)
Net income attributable to unvested shares		(404)		(121)		(754)		—
Numerator for basic		31,317		7,497		46,720		(44,586)
Net (income) loss attributable to unvested shares		—		—		—		—
Numerator for dilutive	$	31,317	$	7,497	$	46,720	$	(44,586)

Weighted average shares (denominator):
Basic weighted average shares outstanding		58,586		57,456		58,102		57,628
Effect of dilutive securities		330		285		552		—
Diluted weighted average shares outstanding		58,916		57,741		58,654		57,628
Stock options and unvested restricted stock grants excluded from dilutive calculation because they would be anti-dilutive		138		1,801		282		3,465

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6. REVENUE

Revenues from contracts with customers are generated from sales in Gabon pursuant to COSPAs. The COSPAs have been and will be renewed or replaced from time to time either with the current buyer or another buyer. The current COSPA with Exxon is scheduled to expire on January 31, 2022. See Note 4 under “Information about the Company’s most significant customers” for further discussion.

COSPAs with customers are renegotiated near the end of the contract term and may be entered into with a different customer or the same customer going forward. Except for internal costs, which are expensed as incurred, there are no upfront costs associated with obtaining a new COSPA.

Customer sales generally occur on a monthly basis when the customer’s tanker arrives at the FPSO and the crude oil is delivered to the tanker through a connection. There is a single performance obligation (delivering crude oil to the delivery point, i.e. the connection to the customer’s crude oil tanker) that gives rise to revenue recognition at the point in time when the performance obligation event takes place. This is referred to as a “lifting”. Liftings can take one to two days to complete. The intervals between liftings are generally 30 days; however, changes in the timing of liftings will impact the number of liftings that occur during the period. Therefore, the performance obligation attributable to volumes to be sold in future liftings are wholly unsatisfied, and there is no transaction price allocated to remaining performance obligations. The Company has utilized the practical expedient in ASC Topic 606-10-50-14(a), which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

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

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

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

In addition to revenues from customer contracts, the Company has other revenues related to contractual provisions under the Etame Marin block PSC. The Etame Marin block PSC is not a customer contract, and therefore the associated revenues are not within the scope of ASC 606. The terms of the Etame Marin block PSC include provisions for payments to the government of Gabon for royalties based on 13% of production at the published price, and a shared portion of “Profit Oil” determined based on daily production rates as well as a gross carried working interest of 7.5% (increasing to 10% beginning June 20, 2026) for all costs. For both royalties and Profit Oil, the Etame 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.

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

With respect to the government’s share of Profit Oil, the Etame Marin block PSC provides that the corporate income tax liability is satisfied through the payment of Profit Oil. In the condensed consolidated statements of operations, the government’s share of revenues from Profit Oil is reported in revenues with a corresponding amount reflected as current income tax expense. These sales are not considered revenues under a customer contract as the Company is not a party to the contracts with the buyers of this crude oil. However, consistent with the reporting of Profit Oil in prior periods, the amount associated with the Profit Oil under the terms of the Etame Marin block PSC is reflected as revenue with an offsetting amount reported as a current income tax expense. Payments of the income tax expense will be reported in the period that the government takes its Profit Oil in-kind, i.e. the period in which it lifts the crude oil. An in-kind payment of $20.1 million was made with the September 2021 lifting. With the September lifting, the government lifted more oil in-kind than what was owed to it in foreign taxes. Therefore, the Company has a $2.1 million foreign income tax receivable as of September 30, 2021. As of December 31, 2020, the foreign taxes payable attributable to this obligation was $0.9 million.

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Revenue from customer contracts:	(in thousands)
Sales under the COSPA	$	42,056	$	13,797	$	136,693	$	53,057
Other items reported in revenue not associated with customer contracts:
Gabonese government share of Profit Oil taken in-kind		20,103		6,883		20,103		8,738
Carried interest recoupment		1,794		280		5,948		1,273
Royalties		(8,054)		(2,704)		(20,048)		(8,449)
Crude oil and natural gas sales	$	55,899	$	18,256	$	142,696	$	54,619

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 September 30, 2021		As of December 31, 2020
	(in thousands)
Crude oil and natural gas properties and equipment - successful efforts method:
Wells, platforms and other production facilities	$	480,872	$	441,879
Work-in-progress		2,278		169
Undeveloped acreage		23,735		21,476
Equipment and other		18,694		9,276
		525,579		472,800
Accumulated depreciation, depletion, amortization and impairment		(451,477)		(435,764)
Net crude oil and natural gas properties, equipment and other	$	74,102	$	37,036

Extension of Term of Etame Marin Block PSC

On September 25, 2018, VAALCO, together with the other joint venture owners in the Etame Marin block (the “Consortium”), received an implementing Presidential Decree from the government of Gabon authorizing an extension for additional years (“PSC Extension”) to the Consortium to operate in the Etame Marin block. The Company’s subsidiary, VAALCO Gabon S.A., currently has a 63.575% participating interest (working interest including the working interest attributable to the carried interest owner) in the Etame Marin block.

The PSC Extension extended the term for each of the three exploitation areas in the Etame Marin block for a period of ten years with effect from September 17, 2018, the effective date of the PSC Extension. The PSC Extension also granted the Consortium the right for two additional extension periods of five years each. The PSC Extension further allows the Consortium to explore the potential for resources within the area of each Exclusive Exploitation Authorization as defined in 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 two development wells and two appraisal wellbores during the 2019/2020 drilling campaign with the last appraisal wellbore completed in February 2020. During September 2020, the Consortium completed the two 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 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 Consortium an additional 2.5% gross working interest carried by the Consortium effective June 20, 2026. VAALCO’s share of this interest to be transferred to the government of Gabon is 1.6%.

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Proved Properties

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

There was no triggering event in the three and nine months ended September 30, 2021 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher future strip prices for the third quarter of 2021 compared to the second quarter of 2021, and that the Company incurred no significant capital expenditures in the period related to the Etame Marin block.

There was no triggering event in the third quarter of 2020 that would cause the Company to believe the value of crude oil and natural gas producing properties should be impaired. Factors considered included higher future strip prices for the third quarter of 2020 compared to the second quarter of 2020, and that the Company incurred no significant capital expenditures in the period related to the Etame Marin block. Declining forecasted oil prices in the first quarter of 2020 caused the Company to perform an impairment review during this period. The impairment test was performed using the year end 2019 independently prepared reserve report, estimated reserves for the South East Etame 4H well completed in March 2020 and forward price curves. The Company performed a recoverability test as defined under ASC 932 and ASC 360, noting that the undiscounted cash flows related to the Etame Marin block were less than the book value for the block, resulting in the Company recording a $30.6 million impairment loss to write down the Company’s investment to its fair value of $15.6 million.

Undeveloped Leasehold Costs

VAALCO acquired a 31% working interest in an undeveloped portion of a block (“Block P”) offshore Equatorial Guinea in 2012. The Ministry of Mines and Hydrocarbons (“EG MMH”) approved our appointment as operator for Block P on November 12, 2019. The Company acquired an additional working interest of 12% from Atlas Petroleum, thereby increasing its working interest to 43% in 2020, in exchange for a potential future payment of $3.1 million in the event that there is commercial production from Block P. On August 27, 2020, the amendment to the production sharing contract to ratify the Company’s increased working interest and appointment as operator was approved by the EG MMH. On April 12, 2021, the majority of non-defaulting parties assigned the defaulting party’s interest to the non-defaulting parties. As a result, VAALCO’s working interest will increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. As of September 30, 2021, the Company had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. The Company has completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P. VAALCO is now proceeding to a field development concept and will work closely with the other joint venture owners to complete this over the coming months. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

As a result of the PSC Extension discussed above, the exploitation area for the Etame Marin block was expanded to include previously undeveloped acreage. The Company allocated $6.7 million of the share of the signing bonus and $7.1 million of the $18.6 million resulting from the deferred tax impact for the difference between book basis and tax basis to unproved leasehold costs using the acreage attributable to the previous exploitation areas and the additional acreage in the expanded exploitation areas. Exploitation of this additional area is permitted throughout the term of the Etame 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 September 30, 2021 was $13.7 million.

Capitalized Equipment Inventory

Capitalized equipment inventory is reviewed regularly for obsolescence. Adjustments for inventory obsolescence are recorded in the “Other operating income (expense), net” line item of the condensed consolidated statements of operations but were not material for the three and nine months ended September 30, 2021 and 2020.

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 price 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 price 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

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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. See the table below for the unexpired barrels as of September 30, 2021.


Settlement Period	Type of Contract	Index	Barrels	Weighted Average Price
October 2021 to January 2022	Swaps	Dated Brent	236,421	$	53.10
October 2021	Swaps	Dated Brent	108,882	$	66.00
November 2021 to February 2022	Swaps	Dated Brent	314,420	$	67.70
March 2022 to June 2022	Swaps	Dated Brent	460,000	$	72.00
			1,119,723

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

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

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

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


		Three Months Ended September 30,				Nine Months Ended September 30,
Derivative Item	Statement of Operations Line	2021		2020		2021		2020
		(in thousands)
Crude oil swaps	Realized gain (loss) - contract settlements	$	(4,186)	$	—	$	(10,189)	$	7,216
	Unrealized loss		(961)		—		(10,881)		(633)
	Derivative instruments gain (loss), net	$	(5,147)	$	—	$	(21,070)	$	6,583

9. ACCRUED LIABILITIES AND OTHER

Accrued liabilities and other balances were comprised of the following:


	As of September 30, 2021		As of December 31, 2020
	(in thousands)
Accrued accounts payable invoices	$	12,447	$	4,070
Gabon DMO, PID and PIH obligations		8,531		3,960
Derivative liability - crude oil swaps		10,881		—
Capital expenditures		2,475		435
Stock appreciation rights – current portion		761		2,289
Accrued wages and other compensation		2,411		2,108
Other		2,351		4,322
Total accrued liabilities and other	$	39,857	$	17,184

10. COMMITMENTS AND CONTINGENCIES

Abandonment funding

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. The amounts paid will be reimbursed through the Cost Account and are non-

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refundable. The abandonment estimate used for this purpose is approximately $61.8 million ($36.4 million net to VAALCO) on an undiscounted basis. Through September 30, 2021, $37.9 million ($22.3 million net to VAALCO) on an undiscounted basis has been funded. This cash funding is reflected under “Other noncurrent assets” in the “Abandonment funding” line item of the condensed consolidated balance sheet. 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 September 30, 2021, the foreign currency loss associated with the abandonment funding account was $0.6 million. During the nine months ended September 30, 2021, the Company recorded $1.1 million in foreign currency losses associated with the abandonment funding account. Amendment No. 5 to the Etame Marin block PSC provides that in the event that the Gabonese bank fails for any reason to reimburse all of the principal and interest due, 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.

FPSO charter

In connection with the charter of the FPSO, the Company, as operator of the Etame Marin block, guaranteed all of the charter payments under the charter through its contract term. At the Company’s election, the charter could be extended for two one-year periods beyond September 2020. These elections have been made, and the charter has been extended through September 2022. The Company obtained guarantees from each of the Company’s joint venture owners for their respective shares of the payments. The Company’s net share of the charter payment is 58.8%, or approximately $19.4 million per year. Although the Company believes the need for performance under the charter guarantee is remote, the Company recorded a liability of $0.1 million as of September 30, 2021 and $0.4 million as of December 31, 2020 representing the guarantee’s estimated fair value. The guarantee of the offshore Gabon FPSO charter has $32.1 million in remaining gross minimum obligations as of September 30, 2021.

Regulatory and Joint Interest Audits and Related Matters

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

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

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

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

FSO

On August 31, 2021, VAALCO and its co-venturers at Etame approved the Bareboat Contract 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) in 2021 and $5 million gross ($3.2 million net) in 2022 of which $6 million will be recovered against future rentals. Current total field level capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO) with about $5 million net expected in 2021 and the remainder in 2022. No other prepayments are required under the FSO Agreements until the vessel is accepted by the Company at the Etame Marin Block location. The Bareboat Contract contains purchase provisions and termination provisions. The Company does not expect to utilize the terminations provision under the FSO Agreements.

Dividend Policy

On August 2, 2021, the Company announced a cash dividend policy beginning in the first quarter of 2022. Additional details of the initial record date and payable date will be announced in early 2022.

Other contractual commitments

In August 2020, the Company entered into an agreement to acquire approximately 1,000 square kilometers 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 of the seismic data began in January 2021. The cost, net to VAALCO, is estimated to be approximately $2.2 million or $3.4 million gross.

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In June 2021, the Company entered into a short-term agreement with an affiliate of Borr Drilling Limited to drill a minimum of three wells with options to drill additional wells. The drilling rig is expected to be delivered after December 1, 2021 and before January 1, 2022.

11. LEASES

Under ASC 842, Leases, 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”) asset and a lease liability at the present value of the future lease payments.

Practical Expedients –The Company elected to use these 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 of ASC 842 resulted in a material increase in the Company’s total assets and liabilities on the Company’s condensed consolidated balance sheet as certain of its operating leases are significant. In addition, adoption resulted in a decrease in working capital as the ROU asset is noncurrent, but the lease liability has both long-term and short-term portions. There was no material overall impact on results of operations or cash flows. In the statement of cash flows, operating leases remain an operating activity.

The Company is currently a party to several lease agreements for the rental of marine vessels and helicopters, warehouse and storage facilities, equipment and the FPSO. The duration for these agreements range from 12 to 26 months. In some cases, the lease contracts require the Company to make payments both for the use of the asset itself and for operations and maintenance services. Only the payments for the use of the asset related to the lease component are included in the calculation of ROU assets and lease liabilities. Payments for the operations and maintenance services are considered non-lease components and are not included in calculating the ROU assets and lease liabilities. For leases on ROU assets used in joint operations, generally the operator reflects the full amount of the lease component, including the amount that will be funded by the non-operators. As operator for the Etame Marin block, the ROU asset recorded for the FPSO, the marine vessels, helicopter, certain equipment and warehouse and storage facilities used in the joint operations includes the gross amount of the lease components.

For all other leases that contain an option to extend, the Company has concluded that it is not reasonably certain it will exercise the renewal option and the renewal periods have been excluded in the calculation for the ROU assets and liabilities. During the third quarter of 2019, the Company notified the lessor of the FPSO of its intent to extend the lease term by the first option that extends the FPSO lease to September 2021. Similarly, during the third quarter of 2020, the Company gave notification to extend the FPSO lease to September 2022.

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

In August 2021, the Company signed the FSO agreements to lease a FSO to replace the current FPSO whose term will end in September 2022. Under the terms of the Bareboat Contract, a third party is expected to improve the leased vessel in order to comply with the Company’s crude-oil production requirements. The vessel is expected to arrive on location in the Etame Marin Block in September 2022 at which time control of the vessel will transfer to the Company.

The discount rate used to calculate ROU assets and lease liabilities represents the Company’s incremental borrowing rate. The Company determined this by considering the term and economic environment of each lease, and estimating the resulting interest rate the Company would incur to borrow the lease payments.

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For the three and nine months ended September 30, 2021 and 2020, the components of the lease costs and the supplemental information were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Lease cost:	(in thousands)
Operating lease cost	$	4,386	$	4,519	$	13,266	$	13,044
Short-term lease cost		585		457		1,828		908
Variable lease cost		1,584		1,715		4,645		5,779
Total lease expense		6,555		6,691		19,739		19,731
Lease costs capitalized		—		11		—		3,470
Total lease costs	$	6,555	$	6,702	$	19,739	$	23,201

Other information:
Cash paid for amounts included in the measurement of lease liabilities:					2021		2020
Operating cash flows attributable to operating leases					$	18,018	$	20,564
Weighted-average remaining lease term						1.0 years		2.0 years
Weighted-average discount rate						6.09%		6.09%

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 September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands)
Production expense	$	3,827	$	2,063	$	10,328	$	6,082
General and administrative expense		49		49		145		147
Lease costs billed to the joint venture owners		2,679		4,586		9,266		15,807
Total lease expense		6,555		6,698		19,739		22,036
Lease costs capitalized		—		4		—		1,165
Total lease costs	$	6,555	$	6,702	$	19,739	$	23,201

The following table describes the future maturities of the Company’s operating lease liabilities at September 30, 2021:


	Lease Obligation
Year	(in thousands)
2021	$	3,489
2022		9,685
2023		179
		13,353
Less: imputed interest		370
Total lease liabilities	$	12,983

Under the joint operating agreements, other joint venture owners are obligated to fund $5.5 million of the $13.4 million in future lease liabilities.

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12. ASSET RETIREMENT OBLIGATIONS

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


(in thousands)	As of September 30, 2021		As of December 31, 2020
Beginning balance	$	17,334	$	15,844
Accretion		1,179		893
Additions		14,564		359
Revisions		—		238
Ending balance	$	33,077	$	17,334

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 Marin block PSC to conduct regular abandonment studies to update the estimated costs to abandon the offshore wells, platforms and facilities on the Etame Marin block. The current abandonment study was completed in November 2018. In 2020, the Company recorded $0.4 million in additions associated with 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 as a result of it increasing its interest in the Etame Marin block.

13. SHAREHOLDERS’ EQUITY

Preferred stock – Authorized preferred stock consists of 500,000 shares with a par value of $25 per share. No shares of preferred stock were issued and outstanding as of September 30, 2021 or December 31, 2020.

Treasury stock – On June 20, 2019, the Board of Directors authorized and approved a share repurchase program for up to $10.0 million of the currently outstanding shares of the Company’s common stock over a period of 12 months. Under the stock repurchase program, the Company could repurchase shares through open market purchases, privately-negotiated transactions, block purchases or otherwise in accordance with applicable federal securities laws, including Rule 10b-18 of the Securities Exchange Act of 1934, as amended (“Exchange Act”). The Board of Directors also authorized the Company to enter into written trading plans under Rule 10b5-1 of the Exchange Act.

From commencement of the plan in June 2019 through April 13, 2020, the Company purchased 2,740,643 shares of common stock at an average price of $1.70 per share for an aggregate purchase price of $4.7 million under the plan. On April 13, 2020, the Board of Directors approved the termination of the share repurchase program; consequently, no further shares can be repurchased pursuant to the plan.

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

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

14. STOCK-BASED COMPENSATION AND OTHER BENEFIT PLANS

The Company’s stock-based compensation has been granted under several stock incentive and long-term incentive plans. The plans authorize the Compensation Committee of the Company’s Board of Directors to issue various types of incentive compensation. The Company had previously issued stock options and restricted shares under the 2014 Long-Term Incentive Plan (“2014 Plan”) and stock appreciation rights under the 2016 Stock Appreciation Rights Plan. On June 25, 2020, the Company’s stockholders approved the 2020 Long-Term Incentive Plan (as amended, the “2020 Plan”) under which 5,500,000 shares are authorized for grants. In June 2021, the Company’s stockholders approved an amendment to the 2020 Plan pursuant to which an additional 3,750,000 shares were authorized for issuance pursuant to awards under the 2020 Plan. At September 30, 2021, 7,558,975 shares were available for future grants under the 2020 Plan.

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

As referenced in the table below, the Company records compensation expense related to stock-based compensation as general and administrative expense associated with the issuance of stock options, restricted stock and stock appreciation rights. During the nine months ended September 30, 2021, the Company settled in cash $3.1 million for stock appreciation rights and received $1.3 million for stock option exercises. During the nine months ended September 30, 2020, the Company did not settle any stock-based

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compensation. Because the Company does not pay significant United States federal income taxes, no amounts were recorded for future tax benefits.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands)
Stock-based compensation - equity awards	$	327	$	322	$	767	$	527
Stock-based compensation - liability awards		(302)		(570)		1,331		(2,624)
Total stock-based compensation	$	25	$	(248)	$	2,098	$	(2,097)

Stock options and performance shares

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

In March 2021, the Company granted options to certain employees of the Company that are considered performance stock options to purchase an aggregate of 401,759 shares at an exercise price of $3.14 per share and a life of ten years. For each performance stock option award, one-third of the underlying shares vest on the later of the first anniversary of the grant date and the date on which the Company’s stock price, determined using a 30-day average, exceeds $3.61 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 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 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 and nine months ended September 30, 2021, no 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 historically paid cash dividends, no expected dividend yield was input to the Black-Scholes or Monte Carlo models. During the nine months ended September 30, 2021 and 2020, the weighted average assumptions shown below were used to calculate the weighted average grant date fair value of option grants under the Monte Carlo model in 2021 and Black-Scholes models.


	Nine Months Ended September 30,
	2021			2020
Weighted average exercise price - ($/share)	$	3.14		$	1.23
Expected life in years		6.0			6.0
Average expected volatility		75	%		74	%
Risk-free interest rate		0.95	%		0.42	%
Weighted average grant date fair value - ($/share)	$	2.07		$	0.79

Stock option activity associated with the Monte Carlo model for the nine months ended September 30, 2021 is provided below:


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2021	644	$	1.23
Granted	402		3.14
Exercised	—		—
Unvested shares forfeited	(687)		1.96
Vested shares expired	—		—
Outstanding at September 30, 2021	359	$	1.96	9.00	$	378
Exercisable at September 30, 2021	74	$	1.23	8.74	$	126

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Stock option activity associated with the Black-Scholes model for the nine months ended September 30, 2021 is provided below:


	Number of Shares Underlying Options	Weighted Average Exercise Price Per Share		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2021	1,804	$	1.38
Granted	—		—
Exercised	(1,088)		1.20
Unvested shares forfeited	(64)		2.33
Vested shares expired	—		—
Outstanding at September 30, 2021	652	$	1.60	1.73	$	876
Exercisable at September 30, 2021	555	$	1.47	1.61	$	816

During the nine months ended September 30, 2021, 504,813 shares were added to treasury as a result of tax withholding on options exercised. During the nine months ended September 30, 2020, no shares were added to treasury as a result of tax withholding on options exercised.

Restricted shares

Restricted stock granted to employees will vest over a period determined by the Compensation Committee that is generally a three-year period, vesting in three equal parts on the anniversaries following the date of the grant. Restricted stock granted to directors will vest on the earlier of (i) the first anniversary of the date of grant and (ii) the first annual meeting of stockholders following the date of grant (but not less than fifty (50) weeks following the date of grant). In March 2021, the Company issued 526,147 shares of service- based restricted stock to employees, with a grant date fair value of $3.14 per share. In June 2021, the Company issued 78,432 shares of service-based restricted stock to directors, with a grant date fair value of $3.06 per share. The vesting of these shares is dependent upon, among other things, the employees’ and directors’ continued service with the Company.

The following is a summary of activity for the nine months ended September 30, 2021:


	Restricted Stock	Weighted Average Grant Date Fair Value
	(in thousands)
Non-vested shares outstanding at January 1, 2021	1,155	$	1.30
Awards granted	605		3.13
Awards vested	(543)		1.28
Awards forfeited	(462)		2.00
Non-vested shares outstanding at September 30, 2021	755	$	2.36

During the nine months ended September 30, 2021, 68,134 shares were added to treasury as a result of tax withholding on the vesting of restricted shares. During the nine months ended September 30, 2020, 40,432 shares were added to treasury as a result of tax withholding on the vesting of restricted shares.

Stock appreciation rights (“SARs”)

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

During the nine months ended September 30, 2021 and 2020, the Company did not grant SARs to employees or directors.

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SAR activity for the nine months ended September 30, 2021 is provided below:


	Number of Shares Underlying SARs	Weighted Average Exercise Price Per Share		Term	Aggregate Intrinsic Value
	(in thousands)			(in years)	(in thousands)
Outstanding at January 1, 2021	2,940	$	1.33
Granted	—		—
Exercised	(2,306)		1.16
Unvested SARs forfeited	(125)		2.33
Vested SARs expired	—		—
Outstanding at September 30, 2021	509	$	1.83	2.23	$	567
Exercisable at September 30, 2021	338	$	1.69	2.10	$	423

Other Benefit Plans

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

15. INCOME TAXES

The income tax provision for VAALCO consists primarily of Gabonese and United States income taxes. The Company’s operations in other 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 income tax returns in all jurisdictions where such requirements exist, with Gabon and the United States being its primary tax jurisdictions.

For interim reporting periods, the Company determines its tax expense by estimating an annual effective 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 recognized in the period in which they occur at the applicable statutory tax rate.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
U.S. Federal:	(in thousands)
Current	$	—	$	147	$	—	$	(378)
Deferred		(17,619)		(442)		(19,668)		9,546
Foreign:
Current		5,516		2,393		15,099		1,876
Deferred		(5,080)		(4,857)		(6,703)		17,426
Total	$	(17,183)	$	(2,759)	$	(11,272)	$	28,470

The Company’s effective tax rate for the nine months ended September 30, 2021 and 2020, excluding the impact of discrete items, was 37.5% and (53%), respectively. For the nine months ended September 30, 2021, 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. Prior to September 30, 2021, the valuation allowance was necessary due to the decline in crude oil prices caused by declining global economic activity and excess oil supply, which impacted the Company’s expected ability to utilize its deferred tax assets. However, the Company’s observation of the increasing crude oil prices over a sustained period of time, lack of disruption in operations due to the pandemic, steady increase in global economic activity and oil supply demand over multiple quarters has removed much of the uncertainty and instability in the industry. The Company’s forecasts show these factors as having a positive impact on future taxable income. On the basis of these factors, the Company determined it was more likely than not that it will realize a portion of our deferred tax assets. Accordingly, the Company reversed $22.3 million of the valuation allowance based on estimated future earnings, which was treated as a discrete item for the three and nine months ended September 30, 2021. Should these factors continue to strengthen, further recognition of additional deferred tax assets may be warranted. The total change in valuation allowances for the nine months ended September 30, 2021 was $(15.8) million. For the three months ended September 30, 2021, the current tax expense of $5.5 million includes a $0.2 million unfavorable oil price adjustment as a result of the change in value of the government’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 $5.3 million for the period. For the nine months ended September 30, 2021, the current tax expense of $15.1 million includes a $1.7 million unfavorable oil price adjustment as a result of the change in value of the government’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 $13.4 million for the period.

As of September 30, 2021, the Company had no material uncertain tax positions. The Company’s policy is to recognize potential interest and penalties related to unrecognized tax benefits as a component of income tax expense.

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

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “Quarterly Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”), which are intended to be covered by the safe harbors created by those laws. We have based these forward-looking statements on our current expectations and projections about future events. These forward-looking statements include information about possible or assumed future results of our operations. All statements, other than statements of historical facts, included in this Quarterly 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 and plans and objectives of management for future operations are forward-looking statements. When we use words such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “forecast,” “outlook,” “aim,” “target,” “will,” “could,” “should,” “may,” “likely,” “plan,” and “probably” or the negative of such terms or similar expressions, we are making forward-looking statements. Many risks and uncertainties that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include, but are not limited to:

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

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

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

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

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

future capital requirements;

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

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

the ability of the consortium to successfully execute its business plan;

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

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

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

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

the impact of competition;

our ability to identify and complete complementary opportunistic acquisitions;

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

weather conditions;

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

currency exchange rates and regulations;

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

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

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

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

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

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

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

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

our ability to enter into new customer contracts;

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changes in customer demand and producers’ supply;

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

actions by our joint venture owners;

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

the outcome of any governmental audit; and

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

The information contained in this Quarterly Report and the information set forth under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2020 (“2020 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 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 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 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. In 2020, crude oil and natural gas prices experienced an unprecedented decline due to a combination of factors, including a substantial decline in global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. For the three and nine months ended September 30, 2021, crude oil prices have improved, there have been no disruptions to operations since the beginning of the pandemic, global economic activity has steadily increased, and oil demand has stabilized over multiple quarters, removing much of the uncertainty and instability in the industry. The continued spread of COVID-19, including vaccine-resistant strains, or repeated deterioration in crude oil and natural gas prices could result in additional adverse impacts on the Company’s results of operations, cash flows and financial position, including further asset impairments. 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

Provisional Award of Two Offshore Blocks in Gabon

The consortium of VAALCO, BW Energy and Panoro Energy were provisionally awarded two blocks in the 12th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of production sharing contracts (“PSCs”) with the Gabonese government. BW Energy will be the operator with a 37.5% working interest, with VAALCO (37.5% working interest) and Panoro Energy (25% working interest) as non-operating joint owners. The two blocks, G12-13 and H12-13, are adjacent to our Etame PSC as well as BW Energy and Panoro’s Dussafu PSC offshore Southern Gabon, and cover an area of 2,989 square kilometers and 1,929 square kilometers, respectively.

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The two blocks will be held by the consortium and the PSCs over the blocks will have two exploration periods totaling eight years which may be extended by a further two 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 one exploration well on each of the two blocks. In the event the consortium elects to enter the second exploration period, the consortium will be committed to drilling at least another exploration well on each of the awarded blocks.

Charter Agreement for the Floating Storage and Offloading Unit

We and our co-venturers at Etame approved the Bareboat Contract and Operating Agreement (collectively, the “FSO Agreements”) with World Carrier Offshore Services Corp. to replace the existing Floating Production, Storage and Offloading unit (“FPSO”) with a Floating Storage and Offloading unit (“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 field level capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO) with about $5 million net expected in 2021 and the remainder in 2022.

Impact on Operations of COVID-19 Pandemic and the Current Crude Oil Pricing Environment

On March 11, 2020, the World Health Organization classified the outbreak of a new strain of coronavirus (“COVID-19”) 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 in the oil and gas industry. The adverse economic effects of the COVID-19 outbreak 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 led to a significant global oversupply of oil and consequently a substantial decrease in crude oil prices in 2020. 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, beginning in July 2020 and continuing through April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. 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. As a result, in July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. See “Liquidity” below for discussion of the unexpired commodity swaps we have in place.

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 repeated 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 further 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.

Further, the impacts of a potential worsening of global economic conditions and the continued disruptions to, and volatility in, the credit and financial markets as well as other unanticipated consequences remain unknown. In addition, we cannot predict the impact that COVID-19 will have on our customers, vendors and contractors; however, any material effect on these parties could adversely impact our business. The situation surrounding COVID-19 remains fluid and unpredictable, 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.

In response to the COVID-19 outbreak and the current pricing environment, we took 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 sharing certain costs, such as supply vessels, helicopter, and personnel with other operators in the region.

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 and while the business environment in 2021 appears to be improving, the situation remains fluid. 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 and have now processed the new 3-D seismic which has allowed us to optimize drilling locations for the 2021/2022 drilling campaign. The seismic data enhanced sub-surface imaging by merging legacy data with newly acquired seismic allowing for the first continuous 3-D seismic over the entire block. In conjunction with the 2021/2022 drilling program, expected to begin in December 2021, we have executed a contract with Borr Jack-Up XIV Inc., an affiliate of Borr Drilling

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Limited, to drill four wells with options to drill additional wells. We expect to spud the Etame 8H side track, the first well of the 2021/2022 drilling program, in early December.

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

Workovers

In October 2021, we completed two workovers on the Ebouri 2-H and the Etame 12-H wells. The workover on the Ebouri 2-H well increased production from about 500 gross barrels of oil per day (“BOPD“)(255 BOPD, net) prior to the workover to approximately 1,400 gross BOPD (715 BOPD, net). For the Etame 12-H well, we replaced both the upper and lower electrical submersible pumps (“ESP”) and reconfigured the ESP design resulting in restored production of about 1,800 gross BOPD (920 BOPD, net).

Acquisition of Additional Working Interest at Etame Marin Block

In November 2020, we signed a sale and purchase agreement (“SPA”) to acquire Sasol Gabon S.A.’s (“Sasol’s”) 27.8% working interest in the Etame Marin block offshore Gabon (the “Sasol Acquisition”). On February 25, 2021, we completed the acquisition of Sasol’s 27.8% working interest in the Etame Marin block offshore Gabon pursuant to the SPA. The effective date of the transaction was July 1, 2020. Prior to the Sasol Acquisition, we owned and operated a 31.1% working interest in Etame. The Sasol Acquisition increased our working interest to 58.8%. As a result of the Sasol Acquisition, the net portion of production and costs relating to our Etame operations increased from 31.1% to 58.8%. Reserves, production and financial results for the interests acquired have been included in our results for periods after February 25, 2021. All assets and liabilities associated with Sasol’s interest in Etame Marin block, including crude oil and natural gas properties, asset retirement obligations and working capital items were recorded at their fair value. 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 condensed consolidated statements of operations. An income tax benefit of $2.2 million, related to the bargain purchase gain, is also included in the condensed consolidated statements of operations. The reason for the bargain purchase gain is mainly due to the lower crude oil price outlook used when the SPA was signed, November 17, 2020, and the higher oil price outlook on February 25, 2021, when the fair value of the reserves associated with the Sasol Acquisition were determined.

The actual impact of the Sasol Acquisition was an increase to “Crude oil and natural gas sales” in the condensed consolidated statement of operations of $26.4 million and $58.0 million for the three and nine months ended September 30, 2021, respectively, and a $10.2 million and $20.1 million increase to “Net income” in the condensed consolidated statement of operations for the three and nine months ended September 30, 2021, respectively. Under the terms of the SPA, a contingent payment of $5.0 million was payable to Sasol should the average Dated Brent price over a consecutive 90-day period from July 1, 2020 to June 30, 2022 exceed $60.00 per barrel. Included in the purchase consideration was the fair value, at closing, of the contingent payment due to Sasol. The conditions related to the contingent payment were met and on April 29, 2021, we paid the $5.0 million contingent amount to Sasol in accordance with the terms of the SPA.

ACTIVITIES BY ASSET

Gabon

Offshore – Etame Marin Block

Development and Production

We operate the Etame Marin Block on behalf of a consortium of companies. As of September 30, 2021, production operations in the Etame Marin block included eleven platform wells, plus three subsea wells tied back by pipelines to deliver crude oil and associated natural gas through a riser system to allow for delivery, processing, storage and ultimately offloading the crude oil from a leased FPSO anchored to the seabed on the block. We currently have fourteen producing wells. The FPSO has production limitations of approximately 25,000 barrels of oil per day and 30,000 barrels of total fluids per day. During the three months ended September 30, 2021 and 2020, production from the block was 1,384 MBbls (708 MBbls net) and 1,500 MBbls (405 MBbls net), respectively, as discussed below in “Results of Operations”. During the nine months ended September 30, 2021 and 2020, production from the Etame Marin block was 4,063 MBbls (1,904 MBbls net) and 4,987 MBbls (1,347 MBbls net), respectively, as discussed below in “Results of Operations”.

Equatorial Guinea

Our working interest will increase to 45.9% once the EG MMH approves a new amendment to the production sharing contract. As of September 30, 2021, we had $10.0 million recorded for the book value of the undeveloped leasehold costs associated with the Block P license. We have completed a feasibility study of a standalone production development opportunity of the Venus discovery on Block P. We are now proceeding to a field development concept and will work closely with the other joint venture owners to complete this over the coming months. The Block P production sharing contract provides for a development and production period of 25 years from the date of approval of a development and production plan.

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Discontinued Operations - Angola

The Angola segment has been classified as discontinued operations in the condensed consolidated financial statements for all periods presented. See Note 3 to the condensed consolidated financial statements for further discussion.

CAPITAL RESOURCES AND LIQUIDITY

Cash Flows

Our cash flows for the nine months ended September 30, 2021 and 2020 are as follows:


	Nine Months Ended September 30,
	2021		2020		Increase (Decrease) in 2021 over 2020
	(in thousands)
Net cash provided by operating activities before changes in operating assets and liabilities	$	43,111	$	22,466	$	20,645
Net change in operating assets and liabilities		3,682		(3,029)		6,711
Net cash provided by continuing operating activities		46,793		19,437		27,356
Net cash used in discontinued operating activities		(72)		(376)		304
Net cash provided by operating activities		46,721		19,061		27,660

Net cash used in investing activities		(30,964)		(22,317)		(8,647)

Net cash used in continuing financing activities		(121)		(990)		869
Net cash used in financing activities		(121)		(990)		869
Net change in cash, cash equivalents and restricted cash	$	15,636	$	(4,246)	$	19,882

The $20.6 million increase in net cash provided by our operating activities before changes in operating assets and liabilities for the nine months ended September 30, 2021 compared to the same period of 2020, was mainly due to higher crude oil prices in 2021 partially offset by changes in impairment, deferred taxes and derivatives. The net increase in operating assets and liabilities of $6.7 million for the nine months ended September 30, 2021 compared to the same period of 2020 was primarily related to changes in foreign taxes payable as a result of the in-kind lifting tax payment valued at $20.1 million in September 2021 and accrued liabilities as a result of starting the 2021/2022 drilling campaign.

Net cash used in investing activities during the nine months ended September 30, 2021 included $22.5 million paid for the completion of the Sasol Acquisition as discussed in Note 3 to our condensed consolidated financial statements. In addition, we incurred on a cash basis $8.5 million for property and equipment primarily related to equipment and enhancements as well as expenditures related to the next drilling program as discussed in “Recent Operational Updates” above. During the nine months ended September 30, 2020, we incurred on a cash basis $22.3 million for expenditures related to the 2019/2020 drilling campaign and equipment purchases. See “Capital Expenditures” below for further discussion.

Net cash used in financing activities during the nine months ended September 30, 2021 included $1.4 million for treasury stock as a result of tax withholding on options exercised and vested restricted stock as discussed in Note 14 to our condensed consolidated financial statements, partially offset by $1.3 million in proceeds from options exercised. Net cash used in financing activities during the nine months ended September 30, 2020 included $1.0 million for treasury stock purchases primarily made under the Company’s stock repurchase plan.

Capital Expenditures

During the nine months ended September 30, 2021, we incurred accrual basis capital expenditures of $11.0 million. These expenditures were primarily related to equipment and enhancements, as well as expenditures related to the next drilling program. The difference between capital expenditures and the property and equipment expenditures reported in the condensed consolidated statements of cash flows is attributable to changes in accruals for costs incurred but not yet invoiced or paid on the report dates. Capital expenditures in 2020 were attributable to expenditures related to the 2019/2020 drilling program and equipment and enhancements. As discussed above, we anticipate beginning a drilling program late in 2021 that will continue into 2022, 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 with about $26 million to about $31 million gross expected in 2021, or about $16 million to $20 million net to VAALCO. In April 2021, we purchased a workover unit to have on site for approximately $1.9 million for future maintenance work.

Contractual Obligations

See Notes 10 and 11 to the condensed consolidated financial statements in this quarterly report as well as Notes 12 and 13 to our 2020 Form 10-K for discussion of our contractual obligations.

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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, 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 for further discussion.

ESG and Climate Change Effects

Environmental, social and governance (“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.

Capital Resources

Cash on Hand

At September 30, 2021, we had unrestricted cash of $52.8 million. The unrestricted cash balance includes $2.3 million of cash attributable to non-operating joint venture owner advances. As operator of the Etame Marin block in Gabon, we enter into project related activities on behalf of our working interest joint venture owners. We generally obtain advances from the joint venture owners prior to significant funding commitments.

We currently sell our crude oil production from Gabon under a term contract that began in February 2020 and, after contract extensions, ends on January 31, 2022. Pricing under the contract is based upon an average of Dated Brent in the month of lifting, adjusted for location and market factors. See Note 8 to the condensed consolidated financial statements for further discussion.

Liquidity

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. 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 2020, crude oil prices experienced a significant decline as a result of the substantial decline in the global demand for crude oil caused by the COVID-19 pandemic and subsequent mitigation efforts. 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. Between July 2020 and April 2021, we temporarily reduced production from the Etame Marin block. Currently, our production is not impacted by OPEC+ curtailments. In July 2021, OPEC+ agreed to increase production beginning in August 2021 to phase out a portion of the prior production cuts. Brent crude prices were approximately $77 per barrel as of September 30, 2021. On January 22, 2021, we entered into commodity swaps at a Dated Brent weighted average price of $53.10 per barrel for the period from and including February 2021 through January 2022 for 709,262 barrels. On May 6, 2021, we 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. Again, on September 24, 2021, the Company entered commodity swaps at a Dated Brent weighted average price of $72.00 per barrel for the period from and including March 2022 to June 2022 for a quantity of 460,000 barrels

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 to our 2021/2022 drilling program and our efforts to secure an alternative to the FPSO charter, through December 2022. However, our ability to generate sufficient cash flow from operations or fund any potential future acquisitions, consortiums, joint ventures or 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

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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.

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. For a discussion of these cash requirements, see the information in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2020 Form 10-K, as well as the following updates.

In connection with the 2020/2021 drilling program, we estimate the range of costs for 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.

In connection with the FSO Agreements, we are required to make 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 field level capital conversion estimates are $40 to $50 million gross ($26 to $32 million net to VAALCO) with about $5 million net expected in 2021 and the remainder in 2022.

On August 2, 2021, we approved the adoption of a cash dividend policy whereby we intend to authorize the payment of quarterly cash dividends of $0.0325 per common share per quarter (full year 2022 annualized of $0.13 per share) beginning in the first quarter of 2022. The declaration of any cash dividends in the future pursuant to VAALCO’s dividend policy will be made at the sole discretion of our Board of Directors each quarter and will depend on a number of factors, including our financial performance and available cash resources, our capital requirements, amount of legally available funds and alternative uses of cash, as well as general business conditions and legal, contractual, tax and regulatory restrictions and other factors our Board of Directors deems relevant at the time it determines to declare such dividends. Our Board of Directors expects to reassess the payment of dividends as appropriate from time to time. For these reasons, as well as others, there can be no assurance that dividends in the future will be equal or similar in amount to that described in this press release or that the Board of Directors will not decide to suspend or discontinue the payment of cash dividends in the future.

Based on current expectations, we believe we have sufficient liquidity through our existing cash balances and cash flow from operations to support these cash requirements

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. In February 2021, we increased our working interest in the Etame Marin block from 31.1% to 58.8%. 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

None.

CRITICAL ACCOUNTING POLICIES

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

NEW ACCOUNTING STANDARDS

See Note 2 to the condensed consolidated financial statements.

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RESULTS OF OPERATIONS

Three Months Ended September 30, 2021 Compared to the Three Months Ended September 30, 2020

Net income for the three months ended September 30, 2021 was $31.7 million compared to net income of $7.6 million for the same period of 2020. See discussion below for changes in revenue and expense.

Crude oil and natural gas revenues increased $37.6 million, or approximately 206.2%, during the three months ended September 30, 2021 compared to the same period of 2020. The increase in revenue is attributable to higher sales prices and higher volumes as a result of the Sasol Acquisition. Further discussion of results by significant line item follows.


	Three Months Ended September 30,
	2021		2020		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		741		412		329
Average crude oil sales price (per Bbl)	$	73.02	$	43.63	$	29.39

Net crude oil revenue	$	55,899	$	18,256	$	37,643

Operating costs and expenses:
Production expense		25,208		8,984		16,224
Exploration expense		479		16		463
Depreciation, depletion and amortization		6,970		2,212		4,758
General and administrative expense		2,940		2,178		762
Bad debt expense		318		151		167
Total operating costs and expenses		35,915		13,541		22,374
Other operating income (expense), net		46		(37)		83
Operating income	$	20,030	$	4,678	$	15,352

The revenue changes in the three months ended September 30, 2021 compared to the same period in 2020 identified as related to changes in price or volume, are shown in the table below:

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


	Three Months Ended September 30,
	2021		2020
Gabon net crude oil production (MBbls)		708		405
Gabon net crude oil sales (MBbls)		741		412

Average realized crude oil price ($/Bbl)	$	73.02	$	43.63
Average Dated Brent spot price* ($/Bbl)		73.51		42.91
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made three liftings during the three months ended September 30, 2021 and three liftings during the three months September 30, 2020. The increase in lifting volumes is due to our increased working interest as a result of the Sasol Acquisition partially offset by natural declines in production. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 98,031 barrels and 36,299 barrels at September 30, 2021 and 2020, respectively.

Production expenses increased $16.2 million, or approximately 180.6%, in the three months ended September 30, 2021 compared to the same period in 2020. The increase in expense was primarily related to higher costs as a result of our increased working interest as a result of the Sasol Acquisition, increased workover costs and higher marine costs. On a per barrel basis, production expense, excluding workover expense, for the three months ended September 30, 2021 increased to $28.85 per barrel from $22.21 per barrel for the three months ended September 30, 2020 primarily as a result of higher marine costs in 2021. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $0.9

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million and $0.4 million in higher costs related to the proactive measures taken in response to the pandemic for each of the three months ended September 30, 2021 and 2020, respectively.

Depreciation, depletion and amortization costs increased $4.8 million, or approximately 215.1% due to higher depletable costs associated with the Sasol Acquisition.

General and administrative expenses increased $0.8 million, or approximately 35.0% in the three months ended September 30, 2021 compared to the same period of 2020. The increase in expense was primarily related to a $0.3 million decrease in SARs benefit related to SARs liability awards that are measured at fair value. The primary driver of changes in the fair value of these awards is changes in our stock price.

Bad debt expense was higher between the three months ended September 30, 2021 and 2020 primarily due to issues of collectability associated with the Value-Added Tax (“VAT”) receivable in Gabon.

Other operating income (expense), net for the three months ended September 30, 2021 and for the three months ended September 30, 2020 was not material to our results.

Derivative instruments loss, net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The $5.1 million loss for the three months ended September 30, 2021 is the result of the continued increase in the price of Brent Crude above the weighted average swap price of our derivative instruments. For the three months ended September 30, 2020 we had no swaps in place. Our current derivative instruments cover a portion of our production through June 2022.

Other, net for the three months ended September 30, 2021 and 2020 primarily consists of foreign currency gains (losses) as discussed in Note 1 to the condensed consolidated financial statements.

Income tax expense (benefit) for the three months ended September 30, 2021 was a benefit of $(17.2) million. This is comprised of $ (22.7) million of deferred tax benefit and a current tax expense of $5.5 million. The deferred income tax benefit for the three months ended September 30, 2021 included a $22.3 million deferred tax benefit from the reversal of the valuation allowance. See Note 15 to the condensed consolidated financial statements. Income tax benefit for the three months ended September 30, 2020 was a benefit of $(2.8) million and included $(5.3) million of deferred tax benefit and a current tax expense of $2.5 million. For both the three months ended September 30, 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.

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Nine Months Ended September 30, 2021 Compared to the Nine Months Ended September 30, 2020

Net income for the nine months ended September 30, 2021 of $47.5 million compared to a net loss of $(44.6) million for the same period of 2020. See the discussion below for changes in revenue and expense.

Crude oil and natural gas revenues increased $88.1 million, or approximately 161.3% during the nine months ended September 30, 2021 compared to the same period of 2020. The increase in revenue is attributable to higher sales prices and to a lesser degree, higher volumes. Further discussion of results by significant line item follows.


	Nine Months Ended September 30,
	2021		2020		Increase/(Decrease)
	(in thousands except per bbl information)
Net crude oil sales volume (MBbls)		2,002		1,337		665
Average crude oil sales price (per Bbl)	$	68.31	$	39.90	$	28.41

Net crude oil revenue	$	142,696	$	54,619	$	88,077

Operating costs and expenses:
Production expense		57,760		30,859		26,901
Exploration expense		1,286		16		1,270
Depreciation, depletion and amortization		16,928		8,116		8,812
Impairment of proved crude oil and natural gas properties		—		30,625		(30,625)
General and administrative expense		12,221		5,951		6,270
Bad debt expense		814		1,140		(326)
Total operating costs and expenses		89,009		76,707		12,302
Other operating expense, net		(440)		(883)		443
Operating income (loss)	$	53,247	$	(22,971)	$	76,218

The revenue changes in the nine months ended September 30, 2021 compared to the same period in 2020 identified as related to changes in price or volume, are shown in the table below:

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


	Nine Months Ended September 30,
	2021		2020
Gabon net crude oil production (MBbls)		1,904		1,347
Gabon net crude oil sales (MBbls)		2,002		1,337

Average realized crude oil price ($/Bbl)	$	68.31	$	39.90
Average Dated Brent spot price* ($/Bbl)		67.89		41.15
*Average of daily Dated Brent spot prices posted on the U.S. Energy Information Administration website.

Crude oil sales are a function of the number and size of crude oil liftings in each quarter from the FPSO, and thus, crude oil sales do not always coincide with volumes produced in any given quarter. We made eight liftings during the nine months ended September 30, 2021 and nine liftings during the nine months ended September 30, 2020. However, the total barrels lifted in the nine months ended September 30, 2021 was more than the barrels lifted during the same period in 2020, mainly due to our increased working interest as a result of the Sasol Acquisition partially offset by natural declines in production. Our share of crude oil inventory aboard the FPSO, excluding royalty barrels, was approximately 98,031 and 36,299 barrels at September 30, 2021 and 2020, respectively.

Production expenses increased $26.9 million, or approximately 87.2%, in the nine months ended September 30, 2021 compared to the same period in 2020. The increase in expense was primarily related to costs as a result of our increased working interest as a result of the Sasol Acquisition, increased workover costs and higher marine and personnel costs. On a per barrel basis, production expense, excluding workover expense, for the nine months ended September 30, 2021 increased to $26.75 per barrel from $21.10 per barrel for the nine months ended September 30, 2020 primarily as a result of a natural decline in oil production and higher marine and personnel costs. While we have not experienced any material operational disruptions associated with the current worldwide COVID-19 pandemic, we have incurred approximately $2.3 million and $1.2 million, respectively, in higher costs related to the proactive measures taken in response to the pandemic for the nine months ended September 30, 2021 and 2020.

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Exploration expenses was $1.3 million for the nine months ended September 30, 2021 as a result of the processing of seismic data acquired at the end of 2020. Exploration costs were not significant for the nine months ended September 30, 2020.

Depreciation, depletion and amortization costs increased $8.8 million, or approximately 108.6%, in the nine months ended September 30, 2021 compared to the same period in 2020 due to higher depletable costs associated with the Sasol Acquisition.

General and administrative expenses increased $6.3 million, or approximately 105.4% in the nine months ended September 30, 2021 compared to the same period of 2020. The increase in expense was primarily related to an additional $4.0 million in SARs expense and an increase of $1.2 million in severance costs associated with changes in key personnel. SARs liability awards are measured at fair value. The primary driver of changes in the fair value of these awards is changes in our stock price. See Note 14 to our condensed consolidated financial statements for further discussion.

Bad debt expense was lower between the nine months ended September 30, 2021 and 2020 primarily due to bad debt expense associated with the VAT allowance.

Other operating expense, net for the nine months ended September 30, 2021 decreased by $0.4 million in expense. The $0.4 million balance for the nine months ended September 30, 2021 is primarily comprised of the difference between the fair value of the contingent consideration paid to Sasol in April 2021, $5.0 million, and the fair value of the contingent consideration on the closing date of the Sasol Acquisition, $4.6 million. The balance of other operating expense for the nine months ended September 30, 2020 relates to an $0.8 million charge for the settlement of a joint venture audit.

Derivative instruments gain (loss), net is attributable to our swaps as discussed in Note 8 to the condensed consolidated financial statements. The $(21.1) million loss for the nine months ended September 30, 2021 is a result of the increase in the price of Dated Brent crude oil above the weighted average swap price of our derivative instruments during the nine months ended September 30, 2021 as compared to a decrease in the price of Dated Brent crude oil that resulted in a $6.6 million gain during the comparable prior year period. Our derivative instruments currently cover a portion of our production through June 2022.

Other, net for the nine months ended September 30, 2021 is primarily attributable to $5.5 million for the bargain purchase gain offset by $1.0 million for an acquisition success fee. Other, net was not significant for the nine months ended September 30, 2020.

Income tax expense (benefit) for the nine months ended September 30, 2021 was a benefit of $ (11.3) million. This is comprised of $ (26.4) million of deferred tax benefit and a current tax expense of $15.1 million. The deferred income tax expense for the nine months ended September 30, 2021 included a $(22.3) million deferred tax benefit from the reversal of the valuation allowance. See Note 15 to the condensed consolidated financial statements. Income tax expense for the nine months ended September 30, 2020 was $28.5 million. This is comprised of $27.0 million of deferred tax expense and a current tax expense of $1.5 million. The deferred income tax expense for the nine months ended September 30, 2020 included a $37.4 million charge to increase the valuation allowances on U.S. and Gabonese deferred tax assets offset by a $(10.5) million deferred tax benefit. For both the nine months ended September 30, 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 African CFA Franc”, or “XAF”), and our VAT receivable as well as certain liabilities in Gabon are also denominated in XAF. A weakening U.S. dollar will have the effect of increasing costs while a strengthening U.S. dollar will have the effect of reducing costs. For our VAT receivable in Gabon, a strengthening U.S. dollar will have the effect of decreasing the value of this receivable resulting in foreign exchange losses, and vice versa. The Gabon local currency is tied to the Euro. The exchange rate between the Euro and the U.S. dollar has historically fluctuated in response to international political conditions, general economic conditions and other factors beyond our control. As of September 30, 2021, we had net monetary assets of $7.3 million (XAF 4,155.5 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) million reduction in the value of these net assets. For the three and nine months ended September 30, 2021, we had expenditures of approximately $10.7 million and $20.4 million (net to VAALCO), respectively, 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 production. Sales prices are primarily driven by

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the prevailing market prices applicable to our production. Market prices for crude oil and natural gas have been volatile and unpredictable in recent years, and this volatility may continue.

Sustained low crude oil prices could have a material adverse effect on our financial condition, the carrying value of our proved reserves, our undeveloped leasehold interests and our ability to borrow funds and to obtain additional capital on attractive terms. If crude oil sales were to remain constant at the most recent quarterly sales volumes of 741 MBbls, a $5 per Bbl decrease in crude oil price would be expected to cause a $3.7 million and $14.8 million decrease per quarter and annualized, respectively, in revenues and operating income and a $3.3 million and $13.3 million decrease per quarter and annualized in net income, respectively.

As of September 30, 2021, we had crude oil swaps outstanding. From time to time, we use derivative instruments as an economic hedge against declines in crude oil prices; however, such instruments are not designated as hedges for accounting purposes. Our derivative instruments only cover a portion of our production through June 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 September 30, 2021, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

The internal control environment was impacted by the stay-at-home requirements for our Houston and Gabon staff which began in mid-March 2020 and was voluntary through September 1 of 2021. From September 1, 2021 through the date of this report the Company has adopted a hybrid schedule where employees are required to be in the office on certain days and allowed to work from home on certain days. 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 (as defined in Rule 13a-15(f) under the Exchange Act), and there were no changes in our internal control over financial reporting that occurred during the three months ended September 30, 2021 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

ITEM 1A. RISK FACTORS

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

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our 2020 Form 10-K. Except as set forth below, there have been no material changes in our risk factors from those described in our 2020 Form 10-K.

If we are not able to timely implement the transition to the FSO unit 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 FPSO to store all of the crude oil we produce prior to sale to our customers. Our current FPSO contract expires in September 2022. On August 31, 2021, we entered into a Bareboat Contract and Operating Agreement for a Floating Storage and Offloading (“FSO”) unit at the Etame Marin field offshore Gabon for up to eight years with additional option periods available upon the expiration of the current FPSO contract in September 2022. The transition to the FSO unit will require a 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 implement the transition to the FSO unit as our alternative method of storing the crude oil we produce, then we will not be able to sell crude oil to our customers. Consequently, we would be required to shut in production until such time that we could offload the oil, and our results of operations would be materially adversely affected.

We may not enter into definitive agreements with the consortium to explore and exploit new properties, and we may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves operated by the consortium or from any non-operated properties we have an interest in.

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On October 11, 2021 we announced our entry into a consortium with BW Energy and Panoro Energy and that the consortium has been provisionally awarded two blocks, G12-13 and H12-13, in the 12^th Offshore Licensing Round in Gabon. The award is subject to concluding the terms of the production sharing contracts with the Gabonese government. BW Energy will be the operator with a 37.5% working interest and we and Panoro Energy will have a 37.5% working interest and 25% working interest, respectively, as non-operating joint owners. The joint owners in the consortium 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. Our obligations within the consortium are subject to a number of conditions, including the negotiation and execution of production sharing contracts with the Gabonese government, as well the entry into joint operating agreements with our joint interest owners. There is no assurance that we will be able to agree to terms on definitive production sharing contracts with the Gabonese government nor joint operating agreements with the joint owners in the consortium. If we are unable to negotiate and enter into definitive agreements with each party, we may not be able to explore, develop and exploit new properties, and our results of operations could be materially adversely affected.

With respect to crude oil and natural gas projects that we do not operate or may not operate in the future, including properties operated by the consortium, we have or will have limited ability to exercise influence over the operations of the non-operated properties and their associated costs, including limited control over the maintenance of safety and environmental standards. Our dependence on the operator and other non-operating joint owners, and our limited ability to influence operations and associated costs of properties operated by others, could prevent the realization of anticipated results in drilling or acquisition activities. In addition, the operator of these properties may act in ways that are not in our best interest. The success and timing of development and exploitation activities on properties operated by others, including those operated by the consortium, depends upon a number of factors that could be largely outside of our control, including:

the timing and amount of capital expenditures;

the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

the operator’s expertise, financial resources and willingness to initiate exploration or development projects;

approval of other participants in drilling wells;

risk of other a non-operator’s failure to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs;

selection of technology;

delays in the pace of exploratory drilling or development;

the rate of production of the reserves; and/or

the operator’s desire to drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

Our operations are subject to risks associated with climate change and potential regulatory programs meant to address climate change; these programs may impact or limit our business plans, result in significant expenditures or reduce demand for our product.

Climate changes continues to be the focus of political and societal attention. Numerous proposals have been made and are likely to be forthcoming on the international, national, regional, state and local levels to reduce the emissions of GHG emissions. These efforts have included or may include cap-and-trade programs, carbon taxes, GHG reporting obligations and other regulatory programs that limit or require control of GHG’s from certain sources. These programs may limit our ability to produce crude oil and natural gas, limit our ability to explore in new areas, or may make it more expensive to produce. In addition, these programs may reduce demand for our product either by incentivizing or mandating the use of other alternative energy sources, by prohibiting the use of our product, by requiring equipment using our product to shift to alternative energy sources, or by directly increasing the cost of fossil fuels to consumers.

An increased societal and governmental focus on ESG and climate change issues may adversely impact our business, impact our access to investors and financing, and decrease demand for our product.

An increased expectation that companies address environmental (including climate change), social and governance (“ESG”) matters may have a myriad of impacts to our business. Some investors and lenders are factoring these issues into investment and financing

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decisions. They may rely upon companies that assign ratings to a company’s ESG performance. Unfavorable ESG ratings, as well as recent activism around fossil fuels, may dissuade investors or lenders from us to toward other industries, which could negatively impact our stock price or our access to capital.

Moreover, while we have and may continue to create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

In addition, ESG and climate chance issues may cause consumer preference to shift toward other alternative sources of energy, lowering demand for our products. In some areas these concerns have caused governments to adopt or consider adopting regulations to transition to a lower-carbon economy. These measures may include adoption of cap-and-trade programs, carbon taxes, increased efficiency standards, prohibitions on the manufacture of certain types of equipment (such as new automobiles with internal combustion engines), and requirements for the use of alternate energy sources such as wind or solar. These types of programs may reduce the demand for our product.

Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, we cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on our financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows.

ITEM 6. EXHIBITS

(a) Exhibits


3.1	Certificate of Incorporation as amended through May 7, 2014 (filed as Exhibit 3.1 to the Company's Quarterly Report on Form 10-Q filed on November 10, 2014 and incorporated herein by reference).
3.2	Third Amended and Restated Bylaws (filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on August 4, 2020 and incorporated herein by reference).
3.3	Certificate of Elimination of Series A Junior Participating Preferred Stock of VAALCO Energy, Inc., dated as of December 22, 2015 (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on December 23, 2015, and incorporated herein by reference).
10.1(a)**	Bareboat Charter, by and between VAALCO Energy, Inc. and World Carrier Offshore Services Corp, dated August 31, 2021.
10.2(a)**	Operating Agreement, by and between VAALCO Energy, Inc. and World Carrier Offshore Services Corp, dated August 31, 2021.
10.3(a)	Deed of Guarantee and Indemnity, by and between VAALCO Energy, Inc. and VAALCO Gabon S.A., dated [August 31, 2021].
10.4(a)	Deed of Guarantee and Indemnity, by and between VAALCO Energy, Inc. and VAALCO Gabon S.A., dated [August 31, 2021].
31.1(a)	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
31.2(a)	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
32.1(b)	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
32.2(b)	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)	Inline XBRL Instance Document.
101.SCH(a)	Inline XBRL Taxonomy Schema Document.
101.CAL(a)	Inline XBRL Calculation Linkbase Document.
101.DEF(a)	Inline XBRL Definition Linkbase Document.
101.LAB(a)	Inline XBRL Label Linkbase Document.
101.PRE(a)	Inline XBRL Presentation Linkbase Document.
104	Cover Page Interactive Data File (Formatted as Inline XBRL and contained in Exhibit 101).

(a) Filed herewith

(b) Furnished herewith

* Management contract or compensatory plan or arrangement.

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

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SIGNATURE

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

VAALCO ENERGY, INC.

(Registrant)


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

Dated: November 3, 2021